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Full text of "Northern Great Plains Resources Program : cooperative resources study"

333.7 



cLoren cJL, (I5akis 

NORTHERN GREAT PLAINS 
RESOURCE PROGRAM ''''' ''''^'^'^ ^'^'^^^^ 

J UN 1 8 1990 

MONTANA STATE LIBRARY 
1S15 E. 6th AVE. 
A, MONTANA 59620 




NGPRP 

LtAdh \\l\ 



DRAFT REPORT 
September 1974 



NEBRASKA 




i\W 



MONTANA 

NEBRASKA 

NORTH DAKOTA 

SOUTH DAKOTA 

WYOMING 

ENVIRONMENTAL PROTECTION AGENCY 

DEPARTMENT OF AGRICULTURE 

DEPARTMENT OF INTERIOR 



MONTANA STATE LIBRadv 

S 333.7 N10cr 1974 c 1 LIBRARY 




3 0864 00042951 



fsLoren oL, vJai 

NORTHERN GREAT PLAINS 
RESOURCES PROGRAM 



COOPERATIVE RESOURCES STUDY BY: 



MONTANA 

NEBRASKA 

NORTH DAKOTA 

SOUTH DAKOTA 

WYOMING 

ENVIRONMENTAL PROTECTION AGENCY 

DEPARTMENT OF AGRICULTURE 

DEPARTMENT OF INTERIOR 



Coordinated by: 
THE NORTHERN GREAT PLAINS RESOURCES PROGRAM STAFF 

DENVER, COLORADO AND WASHINGTON, D.C. 




September 1974 



Digitized by the Internet Archive 
in 2013 



http://archive.org/details/northerngreatpla19nort 




NGPRP 



Northern Great Plains Resources Program 



ROOM 690, BUILDING 67 
DENVER FEDERAL CENTER 
DENVER, COLORADO 80225 

September 27, 1974 
LETTER OF TRANSMITTAL 



To: Northern Great Plains Resources Program Participants 

From: Program Management Team 

Subject: ileview of Draft Northern Great Plains Resources 
Program Interim Report 



Enclosed is an incomplete draft of the Northern Great Plains 
Resources Program Interim Report. This draft is being 
forwarded so that you may have the opportunity to review 
the contents and provide the Program Management Team with 
your comments prior to final publishing of the Interim 
Report. Many figures and plates are presently being printed 
and therefore are not included in the report. 

We ask that you give this report a critical review and where 
possible provide us with information or references which could 
be used to correct those faults you may identify. 

The Program Management Team will revise the draft where 
inconsistencies are noted and will add a chapter which will 
discuss the issues identified by reviewers but not adequately 
explored in the draft report. 

The reviewer should bear in mind that this draft summarizes 
a vast amount of information generated by the Work Groups 
and the NGPRP staff. It does not examine each issue in 
detail. Instead, it is meant to provide the reader with 
a general understanding of the issues associated with coal 
development in the Northern Great Plains and enable him to 
proceed toward a more critical assessment of specific issues. 

Your comments should arrive at the Program Manager's office 
no later than November 1. The address of the Program Manager 
is: P.O. Box 25007, Building 67, Room 690, Denver Federal 
Center, Denver, Colorado 80225. 



/ 



0Ut^ /a^t^^^^^runt^kjc^ 



John G. VanDerwalker 
Program Manager 



Enclosure 



PREFACE 



The NGPRP Interim Report is an interpretive summary and condensation of a vast amount of 
information assembled by seven work groups. Differences in emphasis and, to a lesser extent, in 
the conclusions expressed in the Interim Report, as compared with the Work Group Reports, are 
due mainly to the broader context in which the Interim Report was considered, and to new data 
and analyses performed subsequent to completion of the Work Group Reports. The Program 
Management Teams bears the responsibility for the conclusions of this Interim Report. These 
conclusions do not necessarily reflect either the positions of the participating States, Federal 
agencies, or the Work Group Leaders. 



CONTENTS 

Letter of transmittal 
Preface 

Section 1974 Page 

PART I-INTRODUCTION ^^^^'E^jjisi qu/\Uty 

COUNCIL 

1-1 National Energy Consumption I-l 

1-2 NGP Coal Resource I-l 

1-3 Concerns of the People 1-2 

1-4 The Northern Great Plains Resources Program 1-4 

1-5 Scope of Report 1-5 



PART II-THE COAL RESOURCES OF THE NORTHERN GREAT PLAINS 

2-1 Issues II-l 

2-2 The Coal Resource II-l 

2-3 Ownership Patterns of the Surface and Mineral Estate II-5 

2-4 Federal and Other Coal Leases II-8 

2-5 Mining Methods 11-10 

(a) Underground Versus Surface Mining 11-10 



PART IlI-ENERGY DEVELOPMENT IN THE NORTHERN GREAT PLAINS 

3-1 Introduction III-l 

3-2 National Energy Consumption Forecast III-2 

3-3 The Need for Additional Energy Supplies III-3 

3-4 The Potential for Energy Conservation III-6 

3-5 Recent Studies III-8 

3-6 Markets for Northern Great Plains Coal III-9 

(a) Export Market for Northern Great Plains Coal Ill- 10 

(b) Market for Northern Great Plains Synthetic Natural Gas .... III-14 

(c) Generation and Export of Electric Power Ill-] 6 

(d) Market Conclusions III-18 

3-7 Federal and State Actions That Might Affect Development III-21 

3-8 Method Used to Assess Range of Potential Changes III-22 

(a) Rational for Use , . III-22 

(b) Siting of Mines and Plants " . III-23 

(c) Importance of Northern Great Plains Coal by CDP III-25 

(d) Current Outlook in Relation to the CDP's III-26 



CONTENTS-Continued 



PART IV-LAND, WATER. AND AIR RESOURCES 
OF THE NORTHERN GREAT PLAINS 



Page 



1 . Land Resources 

4-1 Introduction IV- 1 

(a) Resources of National Importance IV-2 

(b) Resources of Regional Importance IV-2 

4-2 Land Resources IV-4 

(a) Ecosystems of the Northern Great Plains IV-4 

(b) Rehabilitation Potential of the Northern Great Plains Surface 

Minable Lands IV-10 

(c) Impacts of Coal Development on Surface Resources IV- 14 

2. Water Resources 

4-3 Introduction IV-30 

4-4 Historic Background IV-30 

4-5 Surface Watertlow Conditions IV-31 

(a) Yellowstone River Basin, Montana and Wyoming IV-3 1 

(b) North Dakota Tributaries of the Upper Missouri River IV-32 

(c) Main stem Missouri River IV-32 

4-6 Current Trends and Uses IV-32 

4-7 Water Demand IV-34 

(a) Water for Coal Conversion IV-34 

(b) Water for Municipal and Domestic Use IV-37 

(c) Water for Revegetation of Mined Lands IV-37 

(d) Water for Slurry Pipeline Export IV-38 

(e) Total Potential Water Demand IV-39 

4-8 Water Availabihty IV-40 

(a) Yellowstone River Basin IV-41 

(b) Western Dakota Tributaries IV-43 

(c) Main stem Missouri River IV-43 

(d) Deep Ground Water IV-43 

4-9 Water Costs IV-46 

(a) Surface Water IV-46 

(b) Groundwater IV-46 

(c) Effect of Water Cost on Development IV-49 



CONTENTS-Continued 

Page 

4-10 Issues Wliich May Influence Water Cost Availability or Use IV-50 

(a) Agricultural and Industrial Competition for Water IV-50 

(b) Indian Water Riglits IV-50 

(c) Article X of the Yellowstone River Compact IV-51 

4-11 Impacts of Water Development IV-52 

(a) Water Quality IV-52 

(b) Shallow Ground-Water Impacts . .• IV-61 

(c) Impact of Water Development on Land Resources IV-64 

3. Air Resources 

4-12 Ambient Air Quahty IV-66 

4-13 Impact of Coal Conversion on Air Quahty IV-67 

(a) Primary Impacts IV-67 

(b) Secondary Impacts IV-75 

(c) Potential Constraints to Coal Conversion IV-76 

4-14 Research and Analysis Needs " IV-77 



PART V-THE ECONOMIC, SOCIAL, AND CULTURAL IMPACTS 
OF COAL DEVELOPMENT IN THE NORTHERN GREAT PLAINS 

5-1 Introduction V-1 

5-2 The Principal Impact Area and Changes Expected as a Result of Coal 

Development V-3 

(a) Employment V-3 

(b) Population V-6 

5-3 The Principal Impact Communities and Changes Expected From Coal 

Development V-9 

(a) Labor Supply V-10 

(b) Population V-12 

(c) Institutional and Community Services V-12 

(d) Housing V-16 

(e) Revenues V-1 8 



HI 



CONTENTS -Continued 



Page 



5-4 Impacts on Indians as a Result of Coal Development V-20 

(a) The Six Most Affected Reservations V-21 

(b) Population V-21 

(c) Age V-22 

(d) Labor Force and Employment V-23 

(e) The Indian Family and Income V-24 

(f) Educational Levels V-24 

(g) Anticipated Reservation Coal Development V-25 

5-5 Agriculture and the Changes Expected From Coal Development V-26 

5-6 Agriculture Impact Assessment V-27 

(a) Labor V-27 

(b) Water V-29 

(c) Land V-30 

5-7 Social and Cultural Development V-36 



LIST OF TABLES 



Table 



Page 



2-1 Coal resources of the 63 county study area II-2 

2-2 Estimated coal reserves II-2 

2-3 Surface minable coal reserves of the NGP II-3 

2-4 Underground minable coal reserves of the NGP II-3 

2-5 Acres underlaid by surface minable coal in the NGP II-4 

2-6 Surface and mineral ownership of study area by owner and State .... II-6 

2-7 Federal mineral and surface ownership II-8 

2-8 Federal coal leases in the Northern Great Plains states II-9 

2-9 Federal, State, private, and Indian coal acres under lease in 

NGP states 11-10 

2-10 Comparison of surface and underground mining 11-12 

3-1 Production of coal in NGP states III-l 

3-2 Estimated coal selling price per ton at mine III-l 

3-3 U.S. energy sources ' III-4 

3-4 Petroleum sources III-5 

3-5 Coal production-NGP and other III-9 

3-6 Price of NGP coal in midwest markets compared to prices of 

midwest coal III-l 2 

3-7 Btu values and allowable sulfur content Ill- 13 

3-8 Transportation costs of energy Ill- 15 

3-9 Competitive supplementary gaseous fuels III-l 7 

3-10 Northern Great Plains region— projected additions of electric 

generating capacity (1973-1982) Ill- 19 

3-11 Year 2000 Northern Great Plains III-24 



IV 



LIST OF TABLES-Continued 

Table Page 

3-12 NGP coal production III-25 

3-13 Coal production for each NGP state for each CDF III-26 

4-1 Onsite rehabiUtation costs IV- 12 

4-1 Lands impacted (acres) IV- 15 

4-3 Acres of projected habitat losses to coal development in the study 

area IV- 16 

4-4 Campbell County land area disturbed by mining and coal conversion 

facilities IV-20 

4-5 Bigliom County land area disturbed by mining and coal conversion 

facilities IV-21 

4-6 Rosebud County land area disturbed by mining and coal conversion 

facilities IV-22 

4-7 Oliver and Mercer Counties land disturbed by mining and coal conver- 
sion facilities IV-23 

4-8 Days for which flows of less than 0. 1 ft^ /s were recorded in the 

Yellowstone and Western Dakota tributaries IV-33 

4-9 Federal industrial water option contracts and appUcations as of 

December 1973 IV-35 

4-10 Comparison of potential water use estimates for each CDF during 

years 1980, 1985, and 2000 IV-37 

4-11 Estimated additional municipal water needs for the region IV-38 

4-12 Water requirement for revegetation, year 2000 IV-39 

4-13 Water requirements for slurry pipeline export of coal, 

year 2000 IV-39 

4-14 MRBC projected surface water demands for year 2000 IV-40 

4-15 Coal development related water depletions for 2000 IV-40 

4-16 Water availabihty in the Yellowstone Basin IV-42 

4-17 Water available from Western Dakota tributaries IV-44 

4-18 Main stem Missouri River storage capacity IV-44 

4-19 Water supply systems costs by CDF IV-46 

4-20 Summary of water costs of CDF'S per acre-foot IV-47 

4-21 Comparison of water costs CDF II IV-49 

4-22 Cost of providing water to selected plant sites by 

alternative conveyance system IV-5 1 

4-23 Water quality summary IV-5 5 

4-24 Projected annual average total dissolved sohds concentrations 

resulting from assumed discharge from coal gasification 

and power generating plants IV-58 

4-25 Northern Great Plains mean mixing heiglits IV-66 

4-26 Estimated emissions— 1972 data in tons per year IV-68 

4-27 National ambient air quality standards IV-70 

4-28 NSFS standards IV-71 

4-29 Proposed significant air deterioration IV-72 

4-30 Estimated annual air quality concentrations IV-73 

4-31 Estimated short-term air quality concentrations IV-74 

4-32 Estimated emissions from projected coal conversion facilities 

in tons per year IV-76 

5-1 Total employment-principal impact area 1970-2000 V-4 



LIST OF TABLES-Continued 

Table Page 

5-2 Estimated employment related to coal development V-5 

5-3 Totalpopulationprojections,CDP 1, 11-1980, 1985, 2000 V-7 

5-4 Type of taxes and levels of Government to which the revenues 

accrue V-11 

5-5 Population projections for selected communities CDP I, II, 

111-1980,1985,2000 V-13 

5-6 Number of school children and associated capital cost required 

to provide necessary facihties resulting from the 

operational phase of coal development— selected communities 

CDP II, III- 1980, 1985,2000 V-15 

5-7 Increased housing needs for selected communities— operational 

phase development CDP II, III- 1980, 1985, 2000 V-17 

5-8 Indian land and residents, by reservation, 1973 V-22 

5-9 Indian population change V-22 

5-10 Unemployment rates: North Dakota, South Dakota, and Montana, 

compared to Indian reservations within their 

boundaries, 1970 V-23 

5-11 Family size and income: Indians compared to total population V-24 

5-12 Land use summary-NGP study area by state V-28 

5-13 Cumulative agricultural areas displaced as a result of coal 

development in the NOP Study Area CDP I, II, and III V-31 

5-14 Cropland and associated production displaced annually between 

1980and 2000-CDPIl andlll V-32 

5-15 Total acres of rangeland displaced in study area and value 

foregone 1980-2000, CDP's I, II, and III V-33 

5-16 Total animal units (AU) of grazing in five-county concentrated 

area and displacement— year 2000 V-34 

5-17 Total acres of rangeland displaced in five-county concentrated 

impact area and value foregone- 1980-2000, CDP's I, II, 

and III V-35 



LIST OF FIGURES 

Figure follows page 

3-1 U.S. energy consumption by major source III-4 

3-2 U.S. potential energy production/consumption III-4 

3-3 U.S. nuclear-powered electricity production/consumption III-4 

3-4 U.S. coal production and consumption III-4 

3-5 U.S. petroleum production and consumption III-4 

3-6 U.S. natural gas production and consumption III-4 

3-7 Energy conservation III-IO 

3-8 Forecast of coal production in the Northern Great Plains Ill- 10 

3-9 Estimated average minimum delivered cost of coal in cents per 

milhon Btu- 1980 by unit train III-14 

3-10 Various forms of coal use for each CDP III-22 

4-1 Historic Yellowstone River Basin flows IV-32 



VI 



LIST OF FIGURES-Continued 



Figure 



follows page 



4-2 
4-3 
4-4 
4-5 
4-6 

4-7 

4-8 

4-9 

4-10 

4-11 

4-12 

4-13 

4-14 

4-15 

5-1 

5-2 



5-3 

5-4 
5-5 



Releases from Yellowtail Dam IV-32 

Historic western North Dakota riverflows IV-32 

Releases from Garrison Dam IV-32 

Increase in annual average depletion from 1949 to 1970 IV-32 

Water diverted from Lake Sakakawea for coal conversion facilities in 

North Dakota IV-44 

Atmospheric aspects study area IV-66 

Surface wind roses annual IV-66 

Carbon monoxide- ambient air quality data and standards IV-68 

Particulate matter— ambient air quality data and standards IV-68 

Nitrogen oxides— ambient air quality data and standards IV-68 

Photochemical oxidents and hydrocarbons ambient air quality 

data and standards IV-68 

Sulfur oxides— ambient air quality data and standards IV-68 

Maximum ambient particulate concentrations IV-74 

Maximum ambient SO2 concentrations IV-74 

Northern Great Plains states, principal impact area and major cities . . . V-2 
Estimated annual average construction employment during 

construction of facilities for mining, electrical plants, and 

gasification plants, Campbell County, Wyoming 1975-2000 V-4 

Coal-related employment as compared to agricultural employment 

principal impact area-Montana and Wyoming 1980-2000 V-6 

Anticipated population in the study area for each CDP V-6 

Housing requirements necessary to meet the needs of construction 

workers associated with a single gasification plant and powerplant ... V-18 



LIST OF PLATES (MAPS) 



Plate 

3 

4-6 

5 

7 

8 

10 

A-3 

B-3 

B-4 

B-5 

B-6 

B-7a 

B-7b 

11 



Suitability of dominant soil for rehabilitation 

Potential recreational and scenery resources 

Proposed wilderness and wild lands 

Major ecosystems and surface rehabilitation factors 

Rehabilitation response units 

Surface ownership 

Geologic map of Northern Great Plains 

Surface mineable coal deposits 

Base development forecast 

Most probable development forecast 

Extensive development forecast 

Coal mineral rights ownership— Powder River Basin 

Cameron engineers— Fort Union Region 

Subsurface map— eastern half of Montana 



'These plates 
are presently 
not available 
but will be 
included in 
the final 
report. If 
however, the 
plates are 
received from 
the printer at 
an early date, 
they will be 
forwarded to 
the reposi- 
tories and a 
notice of such 
action will be 
distributed. 



vu 



PART I-INTRODUCTION 

1-1. National Energy Consumption.— AmQrica's energy consumption has grown steadily for 
the past three decades. This has been the result of a population increase, increased industrial 
output, increased construction activities such as housing, and the ever increasing use of electrical 
apphances. All this has resulted in a corresponding increase in the total amount and per capita 
consumption of energy. 

Total energy consumption grew at a rate of 4.8 percent annually for the years 1965-1970. 
Much of the increase in energy needed to meet this growing consumption was supplied by 
imported petroleum. During 1973, about 46 percent of the total energy consumed in the United 
States came from petroleum. Some 38 percent of this petroleum, or 17 percent of the total 
energy consumed, was through the use of imported petroleum. 

The possibility of continuing to expand petroleum imports or increase domestic oil 
production to meet growing consumption is uncertain. There are physical and political 
constraints on how much petroleum supplies can be increased. Domestic production of natural 
gas is limited. Increases in hydropower production are also limited. Nuclear power may make 
significant contributions in the future, but its contribution has not been increasing as fast as had 
been expected. 

The Nation thus faces the question of how it will meet its short to medium term energy 
requirements while alternative sources of energy are being developed. 

1-2. NGP Coal Resource-One possible source of fuel to meet short term energy requirements 
is contained in the coal resources of the Northern Great Plains (NGP). There are many reasons to 
consider Northern Great Plains coal. The amount of coal that can be mined is very large. There 
are 230 billion tons of coal in the Northern Great Plains study area 1,000 feet or less below the 
surface which are minable with current technology. This represents about 24 percent of our 
Nation's total minable coal reserve. A large proportion of this coal lies in thick beds, close to the 
surface, and is readily adaptable to quick and relatively inexpensive surface mining. It is much 
less expensive to mine than surface-mined coal located in other parts of the country and only 
costs one-fourth as much as the underground mining of coal. The sulfur content of NGP coal is 
less than most competitive eastern and midwestern coals, and reclamation costs per ton of coal 



may be less than in other areas because of the higli number of tons to each mined acre and the 
relatively flat terrain. 

The coal from the NGP may be used to supply a variety of fuel demands. It could replace a 
portion of the high sulphur content coal which presently is being burned to generate electricity in 
the midwest. Power generation plants could be erected at the mine sites in the Northern Great 
Plains area and the electricity transmitted on high-voltage lines to areas of high demand. The 
Northern Great Plains coal may also be used for conversion into synthetic gas. 

One consideration in assessing the prospects for Northern Great Plains coal development is its 
economic competitiveness as compared to using coal from other areas. Northern Great Plains coal 
shipped by unit trains to the midwest is, in certain areas, competitive with coal from other areas. 
The costs of electric generation at the mine site, or synthetic gas production, are now high when 
compared to conventional usage; but may become competitive as technology increases. 

Environmental consideration has become increasingly important. Northern Great Plains 
coal is lower in sulfur content than much eastern coal, but because of its low heat value it may 
not be low enough in sulfur content to be burned without special emission controls. If this is the 
case, much of its economic advantage could be eliminated. There is also the possibility of 
developing the considerable resources of higher Btu low sulfur coal available in Kentucky, 
Tennessee, and West Virginia. Reclamation of the arid and semiarid Northern Great Plains 
environment is as yet unproven. Strict environmental standards may make some Northern Great 
Plains coals economically unavailable. All of these uncertainties make analysis of Northern Great 
Plains coal development both more difficult and more important. 

1-3. Concerns of the People. -People who live in the Northern Great Plains express a variety 
of concerns about coal development and have diverging opinions about it— ranging from strong 
opposition to a favorable attitude of support. In identifying the concerns expressed by the 
Northern Great Plains people, it must first be recognized that the Northern Great Plains resources 
and lands are currently being utilized. A casual traveler gains the impression of emptiness or 
openness-the "Big Sky Country." The quality generating this impression is, of course, one of the 
region's assets. But the area is not empty. The regional resources are being used for an economy 
based upon agriculture, tourism, and oil and gas extraction. The areas' social, economic, and 
governmental structures have evolved to meet the needs of this economy. 

The people of the Northern Great Plains generally express concern in terms of their own 



1-2 



interests. For instance, ranchers are concerned about competition for land and water. Many 
ranchers and farmers are concerned about the conversion of present and potential agricultural 
water supplies to industrial usage. Some also believe mined land cannot be reclaimed nor shallow 
aquifers rebuilt, and conclude they will be unable to return mined land to productive uses. Others 
regard coal development as a temporary disruption of the land and seek ways of taking advantage 
of development in ways that will improve existing agricultural conditions. 

Ranchers and farmers are also concerned with air pollution and its impacts on range vegetation 
and crops. The businessmen who derive their livelihood from tourism as well as the tourists 
express concern about the impact of air pollution on the "Big Sky" atmosphere, as well as a 
general concern, shared by most, that the abundant wildlife resources may somehow be reduced 
or their values degraded. 

The several Indian tribes in the region are concerned over how coal development on or near 
their reservations might impact their water rights, resources, and cultural values. Their concerns 
include the hope that coal development might provide jobs and income to alleviate poverty; the 
fear that with coal development they will lose control over their reservation coal resources; and 
that the land base, which is central to the Indian way of life, might be lost. 

Perhaps the deepest concerns are for the possibility of disruption of the stable economic and 
social patterns of the Northern Great Plains. Both urban and rural residents are worried about the 
ability of their communities to absorb the anticipated labor force and the new families that will 
accompany coal development. They are concerned about the impact on schools, police and 
welfare services, sewer and water and other community services. The business community and 
county government managers are uncertain over the nature, size, and timing of increased 
population. They are worried about the time gap between the early need for their investments 
and the later realization of income from taxes and sales. 

A more subtle concern involves the social structure of the communities. How will coal 
development and the resulting influx of labor and industry management change the way people 
live? What kind of people wih the miners, construction workers, and their families be? Where will 
they live? What kind of new power structures will emerge and how will this affect existing social 
and economic groups? 

Clear air, water from their streams and wells, a stable economy, comfortable social structure. 



1-3 



the familiarity of their towns, the quiet: this is what the people of the Northern Great Plains feel 
is threatened. 

Not everyone is fearful about the effects of developing the coal. There are people that view 
the development as something good. They see increasing coal development in terms of an 
expanding economic base, new jobs, better services, and a chance to broaden cultural horizons. 
These people also have a stake in the development of the area and are anxious for it to occur. 

1-4. The Northern Great Plains Resource Program.— The Northern Great Plains Resource 
Program (NGPRP) is a joint effort by the Federal and State governments, as well as industry, 
environmental groups, and other private individuals all of whom are concerned with the effects of 
coal development in the Northern Great Plains. They are concerned that the Nation has an 
adequate supply of energy, and at the same time, would like to be assured that energy 
developments proceed in a way that minimizes adverse environmental and socioeconomic 
impacts. 

The primary objective of the Northern Great Plains Resource Program is to provide 
information and a comprehensive analysis that can be used to place the potential impacts of coal 
development into perspective and thereby assist the people of the Northern Great Plains and the 
Nation in the management of the natural and human resources of this region. Such management 
has been facilitated under the NGPRP by providing a communication and coordination link 
among organizations and activities dealing with the future development of the region so that they 
might function more efficiently and effectively. 

The involvement and interest of all of the participants in the study is many fold. The lead 
Federal agencies— Departments of the Interior and Agriculture, and the Environmental Protection 
Agency— are responsible for such tasks as managing the Federal land, water and mineral resources, 
protecting the quality and quantity of the air and water, studying reclamation potential, and 
providing some services. The States' responsibihties are similar; but on a more local level. The 
environmental groups, industry, and other individuals all have concern in assurance that the study 
be as complete as time allows. 

The NGPRP included a series of investigations and studies conducted by Work Groups in seven 
subject matter categories: Regional Geology; Mineral Resources; Water; Atmospheric Aspects; 
Surface Resources; Social, Economic, and Cultural Aspects; and National Energy Considerations. 



1-4 



The geographic area which these seven Work Groups studied included portions of Montana, 
Wyoming, North Dakota, South Dakota, and Nebraska. The physical resource analyses focused 
on the coal fields of the Fort Union Formation NGP region. Other analyses included this area, 
but in several instances covered a much larger portion of the States in order to treat important 
issues and effects of coal development. 

The Work Group reports were structured to generally include a regional profile section 
describing present conditions in the subject field of interest; a constraints section describing the 
legal, institutional, and other constraints that will affect future regional energy development; and 
an impact analysis section describing the changes which would be expected to occur as a result of 
each of three alternate rates of coal development (Coal Development Profiles). 

The three coal development profiles do not represent plans for development, but are instead 
tools designed to help measure what the effects may be at different rates of development. 

One profile reflects a "low" level of future energy development— enougli to supply regional 
energy requirements and to honor current coal export and electric power generation 
commitments; a second "intermediate" profile conforms to 1973 regional energy supply 
projections performed by the Department of the Interior; and a third, "high" profile foresees the 
Northern Great Plains responding to a long range National energy "emergency." The effects on 
the environmental, social, and economic structure of three different rates of coal development 
are estimated for a timespan from the present to the year 2000. 

1-5. Scope of Report.— Time and data constraints have necessarily limited the scope and 
depth of this NGPRP report. These are recognized and include the following: 

1. The study focuses only on coal and impacts which might occur from coal development, 
since this is the major issue before the public at this point, and because it appears that the 
environmental, social, and economic consequences of coal development would be of the 
greatest importance in the next few years. The area has many other energy resources, which 
are considered in the supply and demand analysis, but not from an impact point of view. 

2. The primary impacts of the three CDPs were estimated as fully as possible. Data and 
time did not permit comprehensively identifying and analyzing all secondary impacts (such as 
the impact of major coal transportation use of railroads on availability of rail facilities for 
agricultural crop export or the impact of developing service industries in South Dakota or 
Nebraska). 



1-5 



3. The three CDPs were hypothesized through the year 2000. The data available indicates 
that the decline of the coal industry in this area would not occur until sometime after the year 
2000. Consequently the impact of mine and other related facility closings was not identified 
and analyzed. 

4. Most of the work groups found major data gaps. These are generally indicated in the 
text of this report and in the work group reports. 

Some of the deficiencies found in this report will be addressed in future efforts of the NGPRP. 



1-6 



PART II-THE COAL RESOURCE OF THE NORTHERN GREAT PLAINS 

2-1. Issues.-The Northern Great Plains region has vast coal deposits beneath its surface. But 
the presence of coal does not automatically ensure that it can be mined. There are a number of 
constraints that could occur which might impede the development of the coal. For instance, the 
unusual ownership pattern of minerals and surface estate may prevent many tons from ever being 
mined; Federal and State leasing regulations may inhibit development; or environmental 
considerations may preclude large amounts of coal from being used. 

It is the purpose of this portion of the report to describe the coal resource and analyze the 
likelihood of its development and to identify and assess the several important issues confronting 
those considering development of NGP coal. In particular, this section will discuss: 

(1) Amount of coal in the Northern Great Plains? 

(2) How much of the available coal can be economically mined? 

(3) How does the quality of coal affect its use? 

(4) How does or how could surface and mineral ownership patterns impede production of 
NGP coal? 

(5) Will the coal resource be large enough to meet forecasted demand even if Federal coal 
underlaying non-Federal surface is not available? 

2-2. The Coal Resource .—The total estimated coal resource in the 63-county study area of 
Montana, North Dakota, South Dakota, and Wyoming is 1,518 bilhon tons' . Of this amount, 835 
bilhon tons are hypothetical resources in unmapped and unexplored areas, 452 billion tons are 
inferred by mapping and field studies, while the remaining 23 1 billion tons are identified 
sufficiently to be classed as minable reserves. Reserves are defined as coal measured and known to 
be there by field studies and minable by current technology. It is not necessarily economical to 
extract and transport to points of use. These deposits generally include coal that is less than 
1,000 feet below the surface and in beds 5 feet or more thick. This is opposed to the resource 
which is defined as the total amount of coal that is thought to be in the ground. The following 
table shows these resources: 



^Data compiled by NGPRP from U.S. Geological Survey, U.S. Bureau of Mines, and State Geological Surveys. 



Tabic 2-1.— Coal resources of the 63 county study area* 
billions of tons 



231 

452 
835 

1,518 



Reserves, measured and indicated by studies, minable 
Inferred studies, not considered minable 
Hypothetical resources, unmapped and unexplored 

Total resource 



*Includes all lignites. Since the Minerals Work Groups completed their 
studies. The definitions have been redefined to exclude lignites that would 
have to be mined by underground methods. 



The 1,518 billion tons are about one-half of the nation's total coal resource ; while 231 billion 
tons (table 2-1) are 48 percent of the nation's minable coal reserve. Table 2-2 presents the 
23 1 -billion-ton coal reserve location by state and by mining method. The surface minable reserves 
shown in the second column are 5 feet or more thick with a maximum of 200 feet of overburden 
for the thickest beds. 

Table 2-2.— Estimated coal reserves 

Seams 5 feet or more thick 

and less than 1 ,000 feet below surface 

(in billions of tons) 





■ 
Total reserves 


Method of recovery 


State 


Surface mining 


Underground mining 


Montana 
Wyoming 
North Dakota 
South Dakota 


158.1 

34.7 

37.5 

1.0 

231.3 


31.9 

19.8 

16.0 

0.4 

*68.1 


126.2 

14.9 

21.5 

0.6 

163.2 



Source: NGRP Mineral Work Group report. 

*The 68. 1 billion tons of coal reserves at depths amenable to surface mining are shown on 
plate B-3. 



Not all of the 68 billion tons of reserves (table 2-2) appropriate for surface mining can be 
recovered. It is estimated that about 20 percent cannot be economically mined because it is 
poorly situated topographically, that is, the reserve is located under a stream or in an area 



II-2 



presently considered environmentally unsound for mining. Therefore 80 percent, or about 54 
billion tons, are thought to be economically recoverable^ by present technology (table 2-3). 

Table 2-3. -Surface minable coal reserves of the NGP (in billions of tons) 



State 


Reserves minable 
by surface methods 


Recoverable reserves 


Montana 
Wyoming 
North Dakota 
South Dakota 


31.9 

19.8 

16.0 

0.4 

68.1 


25.5 

15.8 

12.8 

0.3 

54.4 



Source: NGPRP Mineral Work Group report. 

The percentage of the 162 billion tons of coal that can be recovered by underground mining 
methods may be much lower. The limitations of underground mining technology and economic 
considerations reduce the amount that is thought to be recoverable to 82 biUion tons or 50 
percent of the reserves (table 2-4). 

Table 2-4.— Underground minable coal reserves of the NGP (in billions of tons) 



State 


Reserves minable by 
underground methods* 


Recoverable reserves 


Montana 
Wyoming 
North Dakota 
South Dakota 


126.2 

14.9 

21.5 

0.6 

163.2 


63.1 
7.5 

10.8 
0.3 

81.7 



Source: NGPRP Mineral Work Group report. 
*Conventional room and pillar method. 

Although the 63-county study area encompasses nearly 92 million acres, less than 3 percent, or 
about 2.6 million acres (table 2-5, plate B-3), are underlaid by the surface minable coal discussed 
above. 



Economically Recoverable Reserve: That part of the coal reserve that can be extracted in such a fashion as to be competitive 
with coal from other areas. This does not include the cost of transporting which, when added to the cost of extraction, may 
eleminate it from being competitive with coals from other areas. 

II-3 





Table 2-5.— Acres underlaid by surface minable coal in the NGP 


State 


Acres in study area 
millions 


Acres underlaid by coal 
millions 


Montana 
North Dakota 
South Dakota 
Wyoming 


34.6 
26.7 
11.7 
18.6 

91.6 


1.4 
0.7 
0.1 
0.4 

2.6 



Source: NGPRP Surface Work Group report. 

Of course not all of the 2.6 million acres underlaid by coal would be mined under any 
circumstances. However, additional acreage will be needed for any mine and plant facilities. In 
the section of this report on the Land Resource (sec. 4-2) a discussion is presented on the amount 
of acreage that would be disturbed for mines and plant facilities assuming three different rates of 
development. 

Coal resources of the NGP differ in several respects from those of the rest of the nation: 

(1) Costs of surface mining methods are much lower, because of the thick seams and 
shallow overburden. 

(2) Sulfur content per Btu is lower than nearly all midwestem and most eastern coal. 
(Although it is not necessarily low enough to meet new source pollution standards.) 

(3) High ash and water contents, and higher percentages of volatile hydrocarbons reduce 
the Btu content per pound considerably below that of most eastern coal (and therefore the 
sulfur content must be adjusted upward to compare eastern and NGP coal on a consistent 
sulfur per Btu basis). 

The above factors all affect the marketability of the NGP coal, which is discussed in detail in 
section 3-6. Sulfur content deserves particular mention, since burning NGP coal may be an 
economical method of reducing air pollution. 

A large, percentage of the enormous NGP coal resources has a sulfur content below the 
maximum permissible in Federal New Source Performance Standards (NSPS). (Of the samples 
shown in the Mineral Work Group Report, less than half will meet the standard, however the 
samples are not representative of volumes of coal.) These standards, for sulfur emissions per Btu, 
must be met by all new powerplants. They will limit sulfur emissions from a single plant, however 



11-4 



if the plant is located where there is a concentration of pollutants from other sources even 
stricter standards might be required. 

While a precise assessment of the sulfur content of all the NGP coal resources is not available, 
as the available data does not represent a true sampling, a preliminary study reveals that a high 
percentage of Wyoming coal, a lower percentage of Montana coal, and nearly no lignite coal from 
the Dakotas, meet the New Source Performance Standards. A study was recently completed on 
this at the University of Illinois^ which indicated that the NGP coal contains a much higher 
sulfur content per Btu than has been commonly understood. 

Lignite coal is more likely to be used for gasification than for in-region power generation or 
coal export. Sulfur content is not critical for gasification. 

2-3. Ownership Patterns of the Surface and Mineral Estate .-Starting with the Homestead Act 
of 1862 and through succeeding Acts, the Federal Goverment granted parcels of land to anyone 
willing to work them. The original grants transferred the surface and mineral rights to the land 
but eventually the Federal Government began to reserve the coal and other mineral riglits to the 
homestead lands that were underlaid by a known coal resource. The result is that in the 
homesteaded areas there is a scattered surface ownership pattern (plate 10) with the Federal 
Government controlling the right to mine the coal and other minerals on many acres for which it 
has no surface rights. For instance, in the portions of Montana, North Dakota, and Wyoming 
included in the NGP study area, the Federal Government controls 29 percent of the total mineral 
estate acreage (plate B7a and B7b). Because the Federal Government reserved the mineral rights 
to those acres with a known coal resource, it is estimated that over 60 percent of the total coal 
resource in the study area is located on the 29 percent of the mineral estate controlled by the 
Federal Government." This 60 percent represents about 139 billion tons of the coal reserve (231 
billion tons from table 2-1 times 60 percent). 

Various railroad acts also contributed to a scattered ownership pattern in the study area. They 
provided for grants of considerable land, including coal rights, adjoining the railroad 
rights-of-way. As an example, the Northern Pacific Railroad was given odd-numbered sections (a 
section equals 1 square mile) in a checkerboard pattern for a distance of 40 miles on both sides of 
the right-of-way (plate B-7b). Implementation of these Acts resulted in a checkerboard pattern of 
Federal, railroad, and the private land ownership on either side of the right-of-way. Table 2-6 
summarizes the surface and mineral ownership of the land included in the Northern Great Plains 
study. 



Rieber, Michael "Low Sulfur Coal, A Revision of Reserve and Supply Estimates", CAC doc No. 88, center for Advanced 

Computation University of Illinois, 1973. 
4 
U.S. Department of the Interior, Bureau of Land Management. 

II-5 



Table 2-6.— Surface and mineral ownership of study area 
by owner and State (in percent of total) 





Owner 


State 
(NGPRP 
study 
portion 


Type of 
ownership 


Federal 
acres 


Indian 
acres 


County 
municipal ' 
and private 
acres* 


State 
acres 


Total acres 
million 


Montana 
North Dakota 
South Dakota 
Wyoming 


Surface 
Mineral 
Surface 
Mineral 
Surface 
Mineral 
Surface 
Mineral 


17.0 
33.0 

7.3 
20.3 

5.6 
12.1 
22.9 
42.6 


8.2 
7.9 
2.7 
3.8 
16.6 
18.0 




69.0 

53.3 
87.5 
73.4 
71.9 
57.0 
68.5 
48.7 


5.8 
5.8 
2.5 
2.5 
5.9 
12.9 
8.6 
8.7 


34.6 
26.7 
11.7 
18.6 


Total NOP 


Surface 
Mineral 


13.9 
28.6 


6.0 
6.4 


74.7 
58.7 


5.4 
6.3 


91.6 



Source: NGPRP Surface Work Group report. 

*Includes substantial surface and mineral rights held by the Burlington-Northern Railroad. 



The scattered and mixed ownership patterns found in the NGP complicates coal development 
in a variety of ways. A reasonably large contiguous area is required to make mining economically 
feasible. Rights-of-way for access roads and railroads may be required. Where gasification plants 
or mine-mouth-generating operations are planned, land for plant sites and rights-of-way for 
powerlines and pipelines are necessary. 

To combine rights to enough land having adequate coal reserves to support a logical mining 
unit (which in Campbell County, contains 200-500 million tons of coal) plus obtain the necessary 
rights-of-way, a potential coal developer may be required to deal with many private landowners 
as well as the Federal and State Governments. As stated previously, landowners may or may not 
own mineral rights on areas where they own surface rights and conversely the Federal 
Government often owns the mineral rights but not the surface rights. 

The Federal Government has leased some mineral rights on land where the surface rights are in 
private ownership. A procedure for securing surface rights to land on which the mineral rights are 
under Federal lease was included in the Stockraising Homestead Act of 1916. This Act provided 
that if the surface owner is agreeable to selling or leasing his surface rights, the lessee and the 
surface owner must both agree to the amount of compensation the surface owner will receive. 

II-6 



This agreement may involve the sale of the land, compensation for damages to property that 
might occur, or a periodic payment for the loss of income from taking the land out of crop or 
grazing use. If the surface owner and the lessee cannot come to an agreement, the lessee submits a 
plan and posts a bond (not less than $1,000) to the Secretary of the Interior's representative* 
which would cover payment of compensation for damages. The BLM State Director then reviews 
the plan and the amount of bond and can either disapprove and return the plan to the lessee for 
revision, or can approve the plan and so notify the surface owner. The surface owner then has 30 
days to appeal through the courts. 

As defined by the Homestead Act of 1916, compensation is limited to those things that can be 
easily tabulated— fair market value replacement of a building or compensation for crops out of 
cultivation. But the compensation does not cover the more intangible things such as alteration of 
lifestyle. Determining the monetary compensation appropriately to reimburse a rancher for 
moving his family off a ranch and into town is a difficult problem. How can a value be placed 
upon living in a confined area rather than a wide open space? What compensation should be paid 
to a farmer unable to farm anymore? How much is personal independence worth to a man who 
now must depend on others? All of these questions of values will be raised more and more often 
in the future if increasing numbers of surface owners are asked to relinquish all or part of their 
farms and ranches so that the coal resource can be developed. 

Recently the Senate passed a bill (S.425) that included an amendment (the Mansfield 
Amendment) designed to preclude many of the above questions. The solution offered by this 
amendment is to prevent surface mining any coal under Federal lease on land where the Federal 
Government does not own both the surface and mineral rights. 

To better understand how this amendment, or a similar one, would affect coal development, 
an examination of current Federal leases in the NGP was made. It showed that two-thirds of the 
leased acres (including 65 percent of leased coal) could not be developed if the Federal 
Government had to own both surface and mineral rights. Almost none of the leases in Montana 
and North Dakota could be mined and only about 42 percent of the coal under lease in Wyoming 
could be mined. This is about 6.5 billion of the 9.8 billion tons currently under lease that could 
not be mined. A further evaluation was made of approximately 900,000 acres in the 
Decker-Birney area in Montana.^ This region contains about 15.9 billion tons of recoverable 



Bureau of Land Management State Director. 
^The area was studied by the U.S. Department of the Interior, Bureau of Land Management and the'Forest Service, U.S. 
Department of Agriculture. It is the most intensively studied area in the NGP. Its coal reserves were evaluated by the Northern 
Great Plains Resource Program to determine the possible implications of S.42 5. 

II-7 



surface minable coal. The Federal Government owns both surface and mineral rights on about 
79,000 of the 900,000 acres. Underlaying the 79,000 BLM acres is about 1.4 billion tons of 
recoverable surface minable reserves of coal. The BLM also owns the mineral rights, but not the 
surface rights, to lands that contain an additional 9.73 billion tons of recoverable strippable coal 
reserves. If S.425 or a similar bill were to become law, this 9.73 billion tons or 61 percent of the 
15.9 billion tons now recoverable could not be developed. This 61 percent does not include any 
coal that could legally be developed, but was not in a logical mining unit. 

The House of Representatives recently passed a bill (HR 11500) which addressed the same 
questions. The bill allows Federal coal to be mined by surface methods when the Federal 
Government is not the surface owner, but only when the mining operator obtains the consent or 
acquiescence of the surface owner. The impact of this was not analyzed. The Senate and House 
bills are in conference committee (September 1974). 

No study has been performed of the total number of Federal coal land acres under private 
surface ownership in the NGP study area portion of these states; however, table 2-7 below 
presents these data on a statewide basis ownership for the entire NGP States. 

Table 2-1 .—Federal mineral and surface ownership 









Percent of Federal 




Total acres of 


Federal mineral acres 


mineral acres 


State 


Federal minerals 


under non-Federal surface 


under non-Federal 




millions 


ownership, millions 


ownership 


Montana 


18.8 


10.7 


56.9 


North Dakota 


4.9 


4.8 


98.0 


South Dakota 


1.0 


0.5 


50.0 


Wyoming 


29.3 


11.8 


40.3 




54.0 


27.8 


52.9 



Source: U.S. Department of the Interior, Bureau of Land Management. 

2-4. Federal and Other Coal Leases- At the present time (1974) there are 128 Federal coal 
leases in Montana, North Dakota, and Wyoming and none in South Dakota (plates B7a and B7b). 
These 1 28 leases include about 252,000 acres and represent a minable reserve of about 9.8 billion 
tons of coal (table 2-8). 



II-8 



Table 2-8. -Federal coal leases in the Northern Great Plains States. 


State 


Number 

of 

leases 


Acres under 

lease 
thousands 


Minable reserves 

under lease 

billions 


Montana 
North Dakota 
South Dakota 
Wyoming 


17 

19 



92 


36 

16 



200 


1.1 
0.3 
0.0 
8.4 


Total 


128 


252 


*9.8 



Source: U.S. Department of the Interior, U.S. Geological Survey. 

*Includes 0.6 billion tons of underground minable coal in Wyoming; the remaining 9.2 billion 
tons are considered surface minable. 



Within the time constraint of the study it was not possible to collect information about private 
coal under lease in the Northern Great Plains area. A recent study by two students at the 
University of Wisconsin, Russell Boulding and Francis Cherry'' , provided some information about 
the amount of coal acreage presently under lease in the Northern Great Plains area. Table 2-9 
summarizes the information contained in this study. It was compiled from numerous sources 
such as Federal, State, environmental groups, and other private publications. The Indian data was 
supplemented with Bureau of Indian Affairs information. 

There are no firm estimates of how much of a coal reserve underlays leased state and private 
coal acres. It is estimated that there are 2.5 to 3.5 bilHon tons of coal under lease on the 
Northern Cheyenne and Crow Indian reservations in Montana. The status of these Indian leases is 
not clear. As a result of a recent Supreme Court decision, the Northern Cheyenne Tribe has 
requested the Secretary of Interior to cancel all existing leases and prospecting permits presently 
pertaining to their reservation. The Crow Tribe has asked that similar action be taken on their 
leases under which Westmorland Resources is mining Crow coal from non-Indian surface lands. 
Accordingly, the status of the 77,000 acres of Indian coal leases is uncertain. 



Boulding, Russell, and Cherry, Francis, Coal Leasing Policy in the Northern Plains: The Complexities of Dispersed 
Ownership, University of Wisconsin, 1972. 



II-9 



Table 2-9.— Federal, State, private, and Indian coal acres under lease 
in NGP states (in thousands of acres) 



State 


Federal 

coal acres 

under lease* 


State 

coal acres 

under lease' 


Private 

coal acres 

under lease ' 


Indian 

coal acres 

under lease 


Montana 
North Dakota 
South Dakota 
Wyoming 


36 

16 



200 


58 
No data 
No data 

400t 


334 

1,000 

No data 


91 





Total 


252 


458 


1,334 


91 



*From U.S. Department of the Interior; Bureau of Land Management. 

I Boul ding-Cherry study. 

t Estimated by Boulding-Cherry study from Coal-Mineral Right Ownership Map, Powder River 
Basin, Cameron Engineers, July 1971. The authors stated "this is probably conservative since in 
Sheridan County alone 167,000 acres of State coal land had been leased as of February 1974 
(letter dated April 10, 1974 from Ted Rooney, Powder River Resource Council.)." 

**This information is being compiled by the Powder River Basin Resource Council. 

2-5. Mining Methods. - 

(a) Underground Versus Surface Mining. -The mining technology that is being used for coal 
energy development in the NGP is strip mining; few if any developers have shown an interest in 
underground mining. However, underground mining has found advocates in the NGP who see it 
as a method of retrieving the region's coal resources without destroying the earth's surface and 
others who see it as necessary to provide adequate amounts of coal over the long term. 

Table 2-10 presents a comparison in broad terms of the economics, environmental impact, and 
safety of underground and surface mining techniques. It is clear from a strictly economic 
standpoint that underground mining of coal in the NGP has a weak competitive position. 
Compared to surface mining, capital requirements are higher; labor is scarce and productivity per 
man is relatively low and the actual cost of mining is, as a result, far higher. 

The lower worker productivity of underground mining will increase the socio-economic impact 
of coal development over that caused by surface mining: because, to produce a given amount of 
coal it would take 8 to 10 times as many workers by conventional underground room and pillar 
methods and 3 to 4 times as many to produce it by longwall methods if these mining methods 
prove feasible in the United States. In addition, the specialized skills required by underground 
mining increases the probability that mine workers will come from outside the region, thereby 
compounding the increase in population in the NGP. The increased number of workers and total 



11-10 



population required of underground mining is probably the most significant difference, in terms 
of environmental impacts, between the mining methods. 

Underground mining has been inferior from a worker safety standpoint. New mine safety 
regulations will improve this record, but at considerable expense. It remains uncertain as to 
whether this improvement will make conventional underground mining as safe as surface mining, 
considering the former's inherently hostile environment. 

Conventional room-and-pillar mining, the usual mode of underground mining in the United 
States, is generally inferior to surface mining in terms of resource conservation and, possibly, 
environmental impact (assuming successful rehabilitation of surface-mined land). Room-and-pillar 
mining cannot be used to mine thick seams without low recovery ratios, even when pillars are 
retrieved. The most severe environmental impact of this form of mining is irregular subsidence. 
When it occurs, damage includes surface fissures, sinkholes, cave-ins, and an irregular lowering of 
the land. Horizontal displacement, combined with vertical subsidence, will alter surface and 
ground-water drainage patterns and allow water and air access to the underground workings. The 
intrusion of oxygen may lead to underground burning, and therefore, may promote air and water 
pollution in addition to wasting the resource. Rehabilitation and use of subsiding land is difficult 
if not impossible because the subsidence continues, at irregular intervals, for indefinite periods of 
time. Although techniques such as backfilling of material into the mines can reduce subsidence, 
at present this is uneconomical. 

Subsidence can be Controlled in some cases. When mining relatively shallow seams, removal of 
the pillars in conventional mining encourages subsidence to occur more rapidly leaving only strata 
compaction remaining. To achieve stabilization of the surface, compaction of the disturbed strata 
must occur. In favorable geologic areas, this controlled subsidence leaves the surface relatively 
intact and eliminates any need for major land rehabilitation. Longwall mining, a technique now 
being used in Europe, achieves this effect and is being used to mine thick seams of coal 
(comparable to those of the NGP) with high recovery levels and with minimum surface 
disturbance. Longwall mining is safer than conventional underground mining because the miners 
work beneath a steel roof affording protection against cave-ins. 

It is doubtful though, that longwall mining, or any other type of underground mining, can be 
used to mine thick coal seams with thin overburden. The overburden is not likely to remain 
intact with subsidence resulting from the removal of thick seams. This essentially eliminates these 
NGP coals as a candidate for conventional underground or longwall mining, unless a 



II-] 



substantial technical breakthrough occurs. The extent of surface damage that would be caused by 
longwall mining in deeper beds of the NGP is not presently known and must await further 
research. Conventional underground or longwall mining of deep seams could reduce surface 
subsidence significantly, if not almost totally. As the overburden drops, it fractures and increases 
in volume. Relatively deep seams could be mined without significant surface subsidence because 
the increased volumes would fill the void before the fracturing reached the surface. 

The reserves of both shallow surface-minable coal and deep coal minable by underground 
methods is abundant enough for either source to support high development levels for the short 
term for several decades. The "economically recoverable" surface minable coal reserve is about 
54 biUion tons. Although no analysis has been made of the amount of coal that could be 
economically extracted by longwall methods, assuming it is feasible, it would increase the total 
amount of coal that could be extracted, possibly dramatically. If coal remains a basic energy fuel 
for a long period of time, then underground mining by all available methods may eventually 
become a necessity to provide the coal needed. However, it seems doubtful that underground 
mining will supplant surface mining in the near future in the NGP unless unforeseen land 
rehabilitation problems occur with the latter, or unless significant technological advances in 
longwall mining are made in the near future. 

Table 2-\0.— Comparison of surface and underground mining 



Item 


Surface mining 


Underground mining 


1. Environmental impact 






a. Air pollution 


Considerable dust problem 


Potential pollution and loss 
of resource from underground 
burning, dust problem from 
coal refuse pile 


b. Water pollution 


Reclaimed areas may have 


Subsidence can alter drainage 




greater water infiltration 


systems, leaching from 




and retention than undis- 


above-ground coal refuse 




turbed areas; mining can 


banks 




disturb shallow aquifers; 
leaching from spoil piles 





11-12 



Table 2-10.— Comparison of surface and underground mining .—Continued 



Item 


Surfacing mining 


Underground mining 




c. Surface features 


Not enough fill material for 


Surface subsidence problem 






thick near-surface seams; 


substantial, can be somewhat 






Topographic reclamation is 


controlled but not elimi- 






not difficult in some areas 


nated by longwall mining 






of NGP; some erosion 


if feasible. Can be mini- 






problems in high winds. 


mized or eliminated with 






storms; revegetation is a 


very deep mining 






problem in more arid areas 








or drought years 


4- 


2. 


Time lag to reach full 
production 


6 years* 


3 years' 


3. 


Capital requirements 


$35 milhon for 9-million- 


$75 milhon for two 4.5- 






ton mines 


million-ton mines, con- 
ventional room and pillar 


4. 


Coal prices at mine, 


$5.19 per ton (US), 


$8.87 per ton (US) for 




1971 average 


$2.42 per ton (NGP) 


conventional room and pillar 


5. 


Average labor productivity 


104 tons/man/shift t 


1 2 tons/man/shift for conven- 
tional room and pillar**, 
34 tons/man/shift for 
advanced European longwall § 


6. 


Labor availability 


Good, requires general 


Poor, requires specialized 






construction experience 


training, work has poor 
image 


7. 


Safety-fatal injuries per 


0.2 


0.7-0.8 conventional room 




million short tons, 




and pillar, longwall may be 




1960-70 




significantly less 




Nonfatal injuries per 


-6 


- 27 conventional room and 




million short tons. 




pillar, longwall may be 




1960-70 




significantly less 


8. 


Resource conservation 


80-95 percent (NGP) 


Thin seams 
40-60 percent (room and 
pillar) up to 85 percent 
(retrieving pillars if 
feasible) up to 90 percent 
(longwall, if feasible) 

Thick seams 
Very low conventional 
room and pillar. Higher 
for longwall if feasible 



*Currently 6 years because of large number of equipment orders but may be reduced to 2-3 
years with increased manufacturing capacity. 

'This could increase if large backlog of orders developed. 

t Average of present high productive mines in NGP. This may increase to 170-250 tons per 
man-year in the future. 

**National average. Would be greater with new large mines using latest technology. 

§ Production rate from advanced European longwall techniques. This may be improved if 
applied on large scale in the United States. 



11-13 



PART III.-ENERGY DEVELOPMENT IN THE NORTHERN GREAT PLAINS 

3-1. Introduction— Althou^ 63 counties in three of the Northern Great Plains states contain 
48 percent of the Nation's total coal reserve, coal production in the NGP has never been 
porportional to the size of these reserves. Even with recent growth, it accounted for only 32 
million tons or 5.5 percent of national production in 1973 (table 3-1). The reason for this is that 
the major use of all coal produced in the United States is fuel for electrical generation and the 
Northern Great Plains region is located a much greater distance from most major centers of 
electric generation than are the eastern and midwestern coal fields. Even with the greater 
production cost per ton of eastern and midwestern coal (see table 3-2), the higher delivered price 
per Btu' at major load centers of NGP coal has kept it at competitive disadvantage. 





Table 3 


- 1 .-Production of coal in NGP states (1973) 








Percent of total 


State 




Million tons 


U.S. production 


Montana 




10 


1.7 


North Dakota 




8 


1.4 


Wyoming 




14 


2.4 


Total NGP 




32 


5.5 


Total all states 




590 


100.0 



Table 3-2.— Estimated coal selling price per ton at mine* 



Mine type 


Mine production 
million tons per year 


Selling price of coal f.o.b. 
mine, dollars per ton 


Underground mine, 7 ft. seam 
Strip-Wyoming 
Strip-Montana 
Strip-West Virginia 


5 
5 
5 

3 


7.53 
1.83 
1.64 
4.01 



*Cost analyses of model mines for strip mining of coal in the U.S. Bureau of Mines IC-8535, 
1972: Basic Estimated Capital Investment and Operating Costs for Underground Bituminous Coal 
Mines IC-8632, 1974. 



British thermal unit. 



Until recently coal has been unable to economically compete with the inexpensive petroleum 
and natural gas available during the post-war period. In 1947, coal provided 15.8 quadrillion 
Btu's of energy for domestic consumption. This was 47.9 percent of total U.S. energy 
consumption. By 1973, coal provided only 13.5 quadriUion Btu's of energy and only 17.9 
percent of the U.S. energy total requirements. 

The market conditions for coal in general, and low sulfur coal in particular, have improved 
markedly in the past few years. The demand for low sulfur fuels created by the Clean Air Act of 
1970 has put a premium on NGP coal and has expanded its market area. The mideast oil 
embargo, besides demonstrating the vulnerability of foreign energy supplies, created outright fuel 
shortages that practically eliminated price as a factor in some markets. The greatly increased 
prices of foreign and domestic oil have caused concurrent rises in the market price of coal, 
increasing the distance NGP coal could be profitably shipped. This increase in the price of foreign 
and domestic oil plus the strong growth in total national demand for energy has begun to outstrip 
the rate at which new supphes can be developed, putting development pressure on all sources of 
energy. Thus, there is now strong pressure to move ahead with massive development of NGP coal 
resources. It is the purpose of this part of the report to focus on the renewed interest in NGP coal 
specifically: 

(1) Aspects of national energy consumption affecting production of coal from the NGP 
region, 

(2) Other available energy sources as an alternative to using NGP coal, 

(3) Characteristics of NGP coal that are advantageous or disadvantageous in helping to 
fulfill the national energy requirement, 

(4) Effects energy conservation practices would have on the demand for NGP coal, and 

(5) Effects of Federal and state policy on NGP coal production and development. 

3-2. National Energy Consumption Forecast -Dwnng the period 1947-1973, energy 
consumption increased at an average annual rate of about 3.2 percent, growing from 33.0 
quadrillion Btu's in 1947 to 75.6 quadrillion Btu's in 1973. For the 5-year period 1965-1970, the 
growth rate was 4.8 percent; further increasing to 4.9 percent for 1972 and 1973. 

The Department of the Interior^ predicts that, without energy conservation and with an 
increasing percentage of energy being consumed by electric power generation, national energy 



2 
Dupree, Walter G. and West, J. R. United States Energy Through the Year 2000 Department of the Interior, December 1972 



III-2 



consumption will increase from 75.6 quadrillion Btu's in 1973 to 191.9 quadrillion Btu's in 
2000-an annual growth rate of 3.6 percent. During this time, per capita energy consumption will 
almost double going from 358.1 million Btu's annually in 1973 to 686.1 milhon Btu's in 2000. 

Figure 3-1 illustrates the forecasted increase in U.S. energy consumption and the expected fuel 
sources for this increase. The Interior's forecast assumes, among other things, that: 

(1) The national population would grow at a rate of 1 percent per year. (The current rate of 
population growth is estimated to be 0.7 percent per year.) 

(2) Economic growth would be sustained at about 4.0 percent per year from 1980 to 2000 
(4.3 percent through 1980). (There has been no real growth in the economy during the current 
year and most recent forecasts indicate slow recovery to rates similar to Interior's forecast.) 

(3) Growth in industrial production would be 5 percent per year to 1980 and 4.4 percent 
per year thereafter. 

(4) Supply limitations for fuels were explicitly taken into consideration in the above 
forecasts. 

It should be recognized that this forecast is essentially an extrapolation of current trends based 
on a knowledge of how the various sectors of the economy use energy and how these sectors are 
growing. It does not deal exphcitly with the effect of price changes on the demand and supply of 
energy resources, and consequently, does not recognize any energy savings or supply increases 
that could result from persistent increases in energy prices. Higher energy prices cause energy 
users to reduce energy consumption over a period of time while encouraging energy producers to 
produce more energy than they normally would. For this reason and because of assumption of 
high growth rate of both the economy and the population, the forecast may overestimate energy 
consumption. Others have suggested^ lower growth rates for energy consumption (see 
conservation discussion, sec. 3-4). Nonetheless, the Interior forecast serves as a useful benchmark 
against which to gage the sufficiency of energy suppHes, and the pressure for exploitation of coal 
resources, nationally and in the NGP region. 

3-3. The Need for Additional Energy Supplies -The projected United States consumption of 
imported fuels in the year 2000 will almost equal the total energy consumption in 1973. Figure 
3-2 illustrates the projected role of imported fuels in future U.S. energy consumption. Figures 3-3 
through 3-6 illustrate the forecasted production and consumption of the four major sources of 



See, for example, the NSF-RANN study done by Chapman, Tyrrell, and Mount as summarized in Science, vol. 178, No. 4062 
(17 Nov. 1972), pp. 703-709. There is, however, substantial controversy over their results. 



III-3 



Unites States energy. The dramatic rise in the expected production of nuclear power from 853 
triUion Btu's in 1973 to 47.2 quadrillion Btu's in 2000 illustrates the increasing importance being 
placed on this energy source. It is the only domestic source expected to make significant 
additional contributions, except for coal. Domestic coal production is expected to more than 
double in the next three decades, contributing 34 quadriUion Btu's to the national energy supply 
by 200. On the other hand, domestic supplies of petroleum and natural gas are generally 
expected to be very limited, with total oil production expected to decline and gas production to 
stabilize. The National Petroleum Council"* predicts that U.S. gas production under the most 
favorable circumstances could increase by 50 percent by 1985, but at the same time, the 
differential between national demand and domestic production would double. 

Although there will be incremental increases in geothermal, solar, and hydroelectric energy 
production, their total contribution is relatively insignificant when compared to the total 
anticipated demand (fig. 3-1). 

In 1973, the United States relied mainly upon petroleum and natural gas for energy. Table 3-3 
shows the sources of our present energy supply. 





Table 3-3. 


—U.S. energy sources. 


1973 






Total 






domestic and imported 


Imported only 


Source 




Percent of 




Percent of 




QBtu 


energy 


QBtu 


energy 




quadrillion Btu 


consumption 




consumption 


Petroleum 


34.7 


45.9 


13.0 


17.2 


Natural gas 


23.6 


31.2 


1.1 


1.5 


Coal 


13.5 


17.9 


* 


* 


Hydropower and 










geothermal 


2.9 


3.9 








Nuclear 


0.8 


1.1 








Total 


75.6 


100.0 


14.1 


18.7 



*The United States is a net exporter of coal. 

With the higher prices recently attained by petroleum and natural gas, increased levels of 
exploration can be expected. Additional discoveries are expected to be found in the Outer 



4„ 



U.S. Energy Outlook," National Petroleum Council, Dec. 1972. 



III-4 



200 




1972 1975 



Figure 3-1. U.S. Energy Consumption by Major Source 



200 
190 
180 
170 
160 
150 
140 
130 
120 
110 
100 



90 



CO 



80 



70 



60 



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40 

30 

20 



10 



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PROJECTED ENERGY CONSUMPTION ^fl 


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1985 
YEAR 



2000 



Figure 3-2. U.S. potential energy production/consumption. 



50 



40 



^ 30 

00 



Q 

< 

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10 



m 



1973 1975 



1980 



1985 
YEAR 



2000 



Figure 3-3. U.S. nuclear -powered electricity production/consumption. 



40 



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1980 



1985 



2000 



* Includes coal consumed in generating electricity and converting coal to 
synthetic natural gas. 



Figure 3-4. U.S. coal production and consumption. 




1973 1975 1980 1985 

YEAR 



2000 



Figure 3-5. U.S. petroleum production and consumption. 



50 



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YEAR 
Figure 3-6. U.S. natural gas production and consumption. 



2000 



Continental Shelf, particularly if leasing proceeds at the rate of 10 million acres per year that has 
been proposed. However, the Department of the Interior estimates that domestic oil production, 
including Alaskan production and shale oil, will increase from 21.7 quadriUion Btu's in 1973 to 
only 23.8 quadrillion Btu's in 2000. Production from the conterminous 48 states, including 
offshore areas but excluding shale, is projected to decline from 21.7 quadrillion Btu's to 16.3 
quadrillion Btu's (see table 3-4). 

Table 3A.— Petroleum sources 





1973 


1985 


2000 


Domestic supply 
Conterminous 48 states 
Alaskan north slope 
Synthetic liquids (shale oil) 


*21.7 


18.2 
4.1 
0.5 


16.3 
3.4 

4.2 


Total domestic supply 


21.7 


22.8 


23.9 



*A11 units quadrillion Btu (QBtu). 

Natural gas prices in interstate commerce are regulated and have been held to low levels that 
may have discouraged exploration. At the moment, a partial deregulation-or at least a series of 
allowable price increases-is taking place, and general price increases are anticipated to continue. 
These increases are expected to stimulate exploration for new domestic sources of natural gas 
with additional production from new sources. Nevertheless, the Department of the Interior 
estimates that domestic natural gas production will remain at about 22 quadrillion Btu's through 
the year 2000. 

The combined production of domestic petroleum and natural gas will increase from 44.2 
quadrillion Btu's to 46.3 quadrillion Btu's between 1973 and 2000, including Alaskan oil and 
shale oil. This represents 58.5 percent of the U.S. energy consumption in 1973, but only 24.6 
percent in 2000. The significance of this is that neither domestic petroleum nor natural gas can 
be expected to meet the increases in demand for energy through the year 2000. 

These statistics show that to meet the projected increase in energy demand by 2000 without 
major conservation efforts, the United States will have to obtain as much as 122.7 quadrilhon 
Btu's per year from oil and natural gas imports and from increased nuclear power and coal 



III-5 



production. The Department of the Interior's projection forecasts a breakdown of Btu supply as 
follows: 

Oil imports will be at a level of 47.5 quadrillion Btu's; 
Nuclear power will be increased by 46.4 quadrillion Btu's; 
Coal will be increased by 17.9 quadrillion Btu's; 
Natural gas imports will be at a level of 10.9 quadrillion Btu's. 

If U.S. energy consumption were to continue to follow the current pattern of heavy reliance 
upon petroleum and natural gas, even higher levels of imports than forecasted would be 
necessary. Such heavy dependence upon imported energy could subject the United States to 
poUtical pressures which may be unacceptable, as well as expose the United States to a 
potentially serious and sudden energy shortage if the foreign supply was interrupted. 

3-4. The Potential for Energy Conservation -Ihe Department of the Interior projection did 
not take into account the potential for energy conservation.^ 

Although there has been substantial disagreement as to the effectiveness and potential side 
effects of individual energy conservation strategies, there seems to be a general consensus that 
U.S. energy consumption is not enextricably tied to a growth curve that projects the past into the 
future. A vigorous conservation program could have the effect of slowing national energy demand 
and thus relieving some of the pressures for rapid development of energy resources throughout 
the Nation. The Council on Environmental Quality has estabhshed a year 2000 energy 
consumption level of 121 QBtu's (rather than a projected 191.9 QBtu's) as a goal. 

In the absence of governmental action, a considerable amount of energy conservation can be 
expected in the future simply because of market pressures— as prices for energy increase the 
incentive to conserve energy will also increase. However, the energy market place in the United 
States contains many disincentives to energy conservation that could be overcome by 
governmental action. These disincentives include: 

a. Energy prices do not reflect total costs of environmental damage, and some clean-up 

costs are borne by the general public rather than by energy consumers in proportion to their 



The projections do account, however, for expected savings in energy production and utilization efficiency. In the electrical 
sector, the heat rate (the heat energy needed to generate a unit of electricity for fossil-fueled powerplants) was assumed to decline 
from 10,494 Btu/kWhr in 1971 to 8,500 Btu/kWhr in 2000 for a 19 percent gain in efficiency. For nuclear powerplants, the heat 
rate was assumed to decline from 10,660 Btu/kWhr (represented Light Water Reactor technology) to 9,000 Btu/kWhr 
(representing a mix of light-water high-temperature gas reactors and liquid metal fast breeder reactors, for an efficiency gain of 
i 5.5 percent). In addition, the energy input per dollar of value added in the industrial sector was assumed to decline from 101 to 
79; however, part of this decline is artificial in that it reflects a bookkeeping shift of losses to the electrical sector. 

III-6 



consumption. Thus, energy is underpriced, discouraging some conservation measures that 
would be reahzed at prices reflecting energy's total costs. 

b. Electricity rate structures favors increased consumption. Thus, large consumers who may 
have the most opportunity to conserve energy but are not encouraged to do so by the existing 
rate structure. 

c. Consumers do not have adeuqate information on energy use. Although there is a wide 
range of efficiency among energy-using products doing the same job (automobiles, 
refrigerators, air conditioners, etc.), information about energy costs is often unavailable to the 
consumer. 

d. Energy costs are paid for over a long period of time, whereas the cost of conservation 
measures often is reflected in the initial purchase price of the energy using products and are 
thus more visible and more difficult to pay for because of high interest rates. 

The Government can attack these disincentives either by affecting the cost of energy (by 
restructuring electricity rates, taxing energy in order to recover environmental costs, providing or 
requiring provision of information about energy effectiveness of products, granting tax 
deductions for conservation measures, etc.), or by direct regulation of energy efficiency and use 
(by establishing minimum standards for applicance energy use and home insulation, rationing 
gasoline, restricting parking, etc.). Although there is considerable disagreement about which basic 
type of strategy is best, it seems likely that any broad governmental conservation program will 
contain elements from both. 

There have been several recent studies that have sought to predict the effect on future energy 
demand that may result from the simultaneous establishment of a whole range of conservation 
measures. Although some of these studies are discussed below, they all appear seriously deficient 
in two crucial areas: 

a. They lack serious in-depth analyses of the means by which the conservation measures can 
be implemented. 

b. They fail to adequately consider the potential side effects of the measures on the U.S. 
economy and lifestyle. (The Ford Foundation studies discussed following have not been 
completed and may not deserve these criticisms upon completion.) 



III-7 



3-5. Recent Studies.-A recent National Academy of Engineering study* estimates potential 
savings from a series of energy conservation measures to be 8 to 9 MBPD (million barrels per day) 
of oil equivalent, or 17 to 19 QBtu (quadrillion Btu's) per year, by 1985. This represents about a 
15 percent savings from expected energy levels in that year. The suggested measures include a 
range of industrial conservation measures yielding a 10 percent savings in industrial energy; 
increases in space heating efficiency and better building insulation standards; transportation 
improvements such as carpooling, lower speeds, improved aircraft load factors, smaller 
automobiles, more public transit systems; and improvements in industrial process efficiency. 

The Energy Policy Project of the Ford Foundation has prepared a report on its studies in 
exploring energy sources.''. Two "alternate futures" or scenarios are presented: a "Technical 
Fix," which is calculated to halve the long term 3.4 percent growth rate in U.S. energy while 
maintaining our standard of living and avoiding major alterations in lifestyle, and a "Zero Growth 
Scenario" which would halt energy growth but entail very substantial changes in the U.S. 
economy, in residential patterns, and so forth. 

Although in many ways the "Zero Growth Scenario" is the more interesting of the two, the 
measures necessary to achieve it— a drastic trend away from single family housing; a major shift in 
the U.S. economy towards agriculture and high-technology, low-energy industry (with 
consequent large-scale importing of high-energy products such as fertilizer and aluminum), and 
far greater concentration on service-oriented employment; major shifts in transportation towards 
fewer trips and far greater use of public transportation and so forth— are extraordinarily difficult 
to analyze, with respect to both their possibiUty of being implemented and their potential side 
effects. 

The Technical Fix represents a 17 percent savings in total energy consumption by 1985 (over 
the total consumption assuming no major conservation measures) and a 35 percent savings by 
2000. The actual conservation measures are quite similar in temper to those discussed in the 
Academy of Engineering Report.* The most interesting aspect of the Technical Fix is the 
implications it would have for energy supply. According to the report, the reduction in energy 
demand implied by the scenario would allow the United States to forego extensive development 
of some major new energy sources. For instance, the report says "the nation could choose not to 



U.S. Energy Prospects— An Engineering Viewpoint, Task Force on Energy of the National Academy of Engineering, 
Washington, D.C., 1974. 

'"Exploring Energy Sources", Ford Foundation, Library of Congress catalog card No. 74-77757, 1974. 



III-8 



expand coal mining generally, in either the East or the West, because of environmental or social 
problems, or to restrict surface mining in particular." For instance, a 15 percent energy savings 
represents a quantity of energy that is approximately twice as great as the entire Northern Great 
Plains coal energy contribution to national energy production under the High Profile in the year 
2000. However, such an action would still have to be accompanied by a substantial growth in 
nuclear energy to prevent energy shortages. 

A third prediction of potential energy conservation possibihties has recently been made by the 
Department of the Interior, Office of Energy Conservation. Conservation efforts which involve 
only increases in the efficiency of energy use, but no restrictions on energy use, such as rationing, 
are estimated to be capable of reducing year 2000 consumption from 191.9 to 168.8 QBtu's. 
Details are shown in figure 3-7. 

As noted before, there is no consensus that the energy conservation strategies outHned above 
will achieve the predicted energy savings. It should be clear that a growth rate in U.S. energy 
consumption of only. 1 .7 percent per year— the predicted result of the Technical Fix conservation 
scenario— is quite optimistic. Such a rate is half of the 20-year historical rate— and approximately 
one-third of the rate of the past half decade. Furthermore, even with such a lower rate of growth 
our energy supply problems will not have been solved. The report qualifies the Technical Fix 
scenario by saying, "if the pace and mix of economic growth remains unchanged, energy 
consumption . . . would resume at a higher rate of growth, beyond the year 2000, as new 
opportunities for cutting out waste become harder to find. Even if the . . . growth rate stays at 
1.7 percent per year extended into the next century, a level of 180 quadrillion Btu's (versus 72 in 
1972) would be reached by 2025 and 275 quadrillion Btu's per year by 2050." 

3-6. Markets for Northern Great Plains Coo/. -The Interior consumption forecast provides for 
significant increases in coal production, with NGP coal production increasing at more than the 
proportional amount. Figure 3-8 and table 3-5 show the level of future NGP coal production that 
is consistent with the Department of the Interior's forecast (i.e., CDP II). 



Table 3-5.— Coal production NGP and other 




M 


illion tons (percent of total coal production by weight) 




1973 


1975 


1980 


1985 


2000 


NGP 

Other 


32(5.4) 
566.5 


52(8.2) 
584 


107(14.5) 
633 


197(19.6) 
788 


362(25.5) 
1,056 



III-9 



The expected markets for NGP coal are: 

1. Export of coal from the region, allowing its use in electric powerplants in large portions 
of the United States and particularly the midwest. 

2. The production of synthetic natural gas from coal as less expensive sources of gas 
become unable to meet demands. 

3. The generation of electric energy at mine-mouth plants, and other powerplants in the 
NGP in an effort to supply energy for use both in the NGP region and export. 

The demand for Northern Great Plains coal energy-in the form of coal, CSNG (coal synthetic 
natural gas), or electricity from mine-mouth powerplants, is dependent not only on the demand 
for all energy fuels but also on the competitive position of NGP energy in each of its potential 
market areas. This competitive position in turn depends upon a number of factors that involve 
the availability, price, and environmental attractiveness of the alternative energy sources. 

The predictive analysis must consider all of the following issues: 

—Future environmental restrictions on exploration and exploitation of the alternative energy 
resources, and the consequent effect on their availability and price. 

—Future national poHcy with respect to reliance on imported fuels, and the inverse: foreign 
willingness to supply fuels to U.S. markets. 

—National pohcy on supporting and financing new energy sources and associated research. 

—Future environmental restrictions on fuels used (for instance, restrictions on the sulfur 
content of fuels). 

—Development pace of alternative energy production and pollution control technologies. 

—Future pohcies of utility commissions in market areas. Several of these issues will have, by 
themselves, a very powerful effect on the future viability of NGP energy development. At the 
same time, many of the issues are hard to analyze or predict. 

(a) Export Market for Northern Great Plains Coa/. -The delivered price of NGP coal in the 
midwest exceeds the price of indigenous midwest coal. Coal produced in mines of the NGP states 
is presently transported to steam-electric generating plants located in the West, North Central, 
and East North Central States where recently imposed mandatory limits on permissable levels of 
SO2 emissions have created demand for low sulfur coals and thus, have supported the longer rail 
hauls and higher transportation costs. In unit-train shipments of coal from Montana and 
Wyoming to Minnesota and Illinois, 60-75 percent of the estimated 1973 delivered cost is 
accounted for by transportation. 

III-IO 



200 




1973 1975 1980 1985 

(PRELIMINARY) 

SOURCE: USD I OFFICE OF ENERGY CONSERVATION 

Figure 3- 7. Energy conservation. 



2000 



6000 



5500 



5000 



4500 



4000 



3500 



O 3000 



2500 



2000 



1500 



1000 



500 



wimm 



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%i.;/.. . ^'" li%llilfiiiliiiWii 



1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 
1960-1971 Actual 1975-2000 Forecast 



Figure 3-8. Forecast of coal production in the Northern Great Plains. 



Table 3-6 illustrates the price differential for four NGP mine/midwestem market 
combinations. This difference ranges from 1.1 cents per million Btu's in Minnesota to 19.0 cents 
per million Btu's in Illinois-Indiana. Even greater differences would occur for longer hauls to the 
east. Column 7 of the table reflects the premium per million Btu's currently being paid over the 
delivered cost of midwest coal for NGP coal delivered by unit trains, and the estimated premium 
that would be paid if a 15 million-ton-per-year capacity slurry pipeHne was the method of 
delivery. The data implies that a pipeline of this capacity, if justified by the volume of shipments, 
can deliver NGP coal to many midwestern markets at lower costs than indigenous coal. If one 
adds a medium estimate of the cost of emission control to the cost of midwestern coal, but not 
to the cost of NGP coal, unit train delivery of NGP coal will be at lower Btu cost than 
midwestern coal in many midwestern markets. 

Despite the current lack of economic incentive for shipping NGP coal further than the 
midwest, NGP coal has been shipped as far east as West Virginia. In this latter case, the key 
reason seems to be that some state utility commissions have allowed an automatic pass-through 
of fuel transportation costs (in other words, these costs can be charged directly to the consumer 
without the necessity for hearings), thus allowing Western Coal to successfully "compete" with 
Appalachian coal that is actually priced lower. 

Other factors involved in the shipment of NGP coals outside their traditional market areas 
include: 

-The lack of availability of stack gas desulfurization equipment, which has rendered 
significant quantities of eastern and midwestern high sulfur coals (at least temporarily) 
useless (while NGP coals have been able to comply with air pollution standards). 

—The past Mideast oil embargo, which forced oil-burning powerplants to compete in the coal 
market and drove coal prices up to levels which made long-haul coal shipments economically 
feasible. 

The long-term market for NGP coal depends upon whether this coal can maintain its current 
advantage over competing midwestern and eastern coals. For example, it seems doubtful that the 
automatic pass-through of transportation costs will be a long-term factor in promoting eastern 
markets for NGP coal. There are large deposits of low sulfur coal in the East, especially in 
Kentucky. Although these are deep underground reserves and have considerably greater mining 
costs than do NGP coals, the high transportation costs of NGP coal may curtail its eastern 
markets. 

III-ll 



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III-12 



Another uncertainty with regard to NGP coal's future export markets involves the future price 
and availability of adequate and rehable stack gas cleaning devices for sulfur oxides. The 
Environmental Protection Agency maintains^ ^ that stack gas desulfurization technology is 
available and sufficiently reliable to warrant installation in fossil-fueled powerplants. The utihty 
industry has in general disagreed with this position and contended that presently available 
equipment is too unreliable to be used in a powerplant. Whatever the present situation, however, 
future availability of reliable desulfurization equipment could affect NGP coal markets. 

A further uncertainty in the market for NGP coal lies in the ability of NGP coal to meet low 
sulfur requirements imposed by the Clean Air Act. NSPS (New Source Performance Standards) 
for powerplants under the Act allow for only 1.2 pounds per million Btu's of SO2 emission from 
powerplants. Table 3-7 shows the maximum allowable sulfur content of various quality coals 
based on this requirement. Half of the samples of coal from selected locations in the NGP would 
require the coal to be either pretreated to remove sulfur, burned in powerplants employing stack 
gas cleaning systems, or blended with lower sulfur coal. Data are not available on percentage of 
NGP coal that would require such treatment for use in powerplants. It should be noted that these 
controls may not be as expensive as the high efficiency SO2 controls required for powerplants 
burning higher sulphur coals. 

Additionally, requirements of SIP's (State Implementation Plans) under the Clean Air Act 
limit emissions from existing powerplants, and hence place sulfur limitations on the coal they 
may bum. These requirements may be more or less stringent than the NSPS; in areas of multiple 
sources, they may be more stringent. All of these requirements (NSPS and SIP's) are, of course 
designed to enable the nation to meet National Ambient Air Quality Standards, set to protect 
public health and welfare. 



Table 3-1. -Btu values and allowable sulfur content 


Btu value 


Maximum allowable sulfur 


per pound 


content under NSPS, percent* 


6,000 


0.38 


7,500 


.47 


9,000 


.57 


10,000 


.63 


12,500 


.79 


15,000 


.95 



*Assuming 95 percent conversion of sulfur to gaseous sulfur oxides. 



7a 

Final Report on Projected Utilization of Stack Gas Cleaning Systems by Steam Electric Plants, Sulfur Oxide Control 
Technology Assessment Panel (SOCTAP), April 1973. 

Ill- 13 



Unless outright shortages of competitive fuels occur, the delivered cost of NGP coal will play a 
crucial role in determining its markets. Although the analysis presented previously forecast 
potentially favorable cost advantages for NGP coal, these advantages were computed on the basis 
of 1973 prices. These price advantages may not be stable. The Interagency Coal Task Force for 
Project Independence has estimated the minimum delivered costs for various coals in several 
market areas. Figure 3-9 compares these costs for 1980. (These costs are based on allowing mine 
owners a 15 percent rate of return over the 25-year life of the mine.) An analysis of these 
estimates reveals that NGP deep-mined coals are not competitive in most market areas, usually by 
a very wide margin. The NGP surface-mined coals are roughly competitive with eastern and 
midwestern deep-mined coal in midwestern markets. Although NGP surface-mined coals are not 
strictly competitive with midwestern and eastern surface-mined coal on a delivered cost basis, 
most of these latter coals are high in sulfur content and will require a greater expense in meeting 
NSPS's than will the NGP coal. 

Although Figure 3-9 assumes explicit values for transportation costs, in fact significant 
differences exist between different modes of transportation and, indeed, within each mode 
depending upon the capacity of the mode, its financing arrangements, and its configuration and 
management. Table 3-8 presents cost data for transporting coal in unit trains or through 
pipelines, and compares these to the cost of transporting coal energy, as electricity, through 
high-voltage transmission lines. The data shows that high-capacity slurry pipehnes (where coal is 
mixed with water to form a suspension called "slurry," which is then shipped via pipeline) offer 
some potential for reducing transport costs, but the accuracy of the data for this mode is not as 
certain as the others due to less experience with operating slurry pipelines. 

(b) Market for NGP Synthetic Natural Gas.— A number of energy companies have shown 
substantial interest in developing facilities for the production of CSNG (Coal Synthetic Natural 
Gas) in the Northern Great Plains states and elsewhere, and have invested in research programs 
and plant development planning. Companies who have announced Lurgi-type gasification projects 
in the Northern Great Plains include: 

—Panhandle Eastern Pipe Line Co. and Peabody Coal Co. (one plant in eastern Wyoming); 

-Natural Gas Pipeline Co. of America (one plant in Dunn County, North Dakota); 

-Northern Natural Gas Co. and Cities Service Gas Co. (four plants in the Powder River Basin); 

—Michigan Wisconsin Pipeline Co. (several plants in North Dakota, first plant planned for 
1980). 

III-14 




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Table 3-^. -Transportation costs of energy 






ransport 


Cents/million Btu of primary 
energy/ 100 miles 


Form of energy t 


Range for all 
references 


Likely range for 
Western States 


Slurry pipeline 




1.0-5.0* 

1.3-3.8t 




1.0-5.0 


Unit train 




2.5t 

3.2-600-mile lengthj 

3.9-1,089-mile lengthj 

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2.5-4.0 


Electricity 




2.8-6.4t 

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3.6-4.8, 500 kV a.c* 
4.8-6.6, 345 kV a.c* 
6.6-9.0, 200 kV a.c* 




2.8-9.0 



*The 1970 National Power Survey, Part III, Federal Power Commission, 1971. 
iThe Southwest Energy Study. 

jUnit Train and Volume all-rail Tariffs on Coal Shipments from Montana and 
Wyoming Mines, Branch of Interfuels and Special Studies, Sept., 1973. 
§ Burlington Northern, Inc., Tariffs, September, 1973. 



However, these plants are only in the planning stage and are all subject to cancellation. 

Although massive pipeline construction could expand the market area for NGP CSNG, the 
most probable markets will be those that can be supplied by existing pipehnes. These markets are 
in North and South Dakota, Nebraska, Minnesota, Iowa, Montana, Wyoming, Colorado, Utah, 
California, Nevada, Arizona, Washington, Oregon, and Idaho. 

Implicit in the acceptance of CSNG as a viable product is a belief that over the long term: 

(1) Either the price of gas at the wellhead will continue to be regulated and maintained at a 
level which will insure shortages of natural gas (which would require supplements from other 
higher priced, nonregulated sources) or 

(2) The price of gas will be deregulated, and would rise to (and remain at) such a level that 
provision of supplemental supplies (such as CSNG) would become profitable. 

Without an outright shortage of gas or a substantial price increase for natural gas, CSNG could 
not possibly be a factor in the interstate market. To illustrate: 



III-15 



Prices of high Btu CSNG from western coal range from $0.91 to $ 1 .27 MSCF 

Federal Power Commission Price Ceihng on Interstate Natural Gas Sales-$0.42 MSCF 

Intrastate long-term sales (unregulated) $0.90 to $1.20 MSCF 

Presently, a partial deregulation-or at least a series of allowable price increases-is taking 
place, and general price increases are expected to continue. Most authorities expect these 
increases to stimulate exploration for new domestic sources of natural gas but not to compensate 
for predicted shortfalls in supply. For instance, the National Petroleum Council^ predicts that 
U.S. gas demand will increase from 22 trilhon cubic feet per year in 1970 to more than 41 trillion 
cubic feet per year in 1985, while maximum domestic production will be 30.6 triUion cubic feet' 
per year (under extremely favorable circumstances). This very substantial gap would have to be 
made up by supplementary supplies, including (potentially) Northern Great Plains synthetic gas 
(if the shortages occur in areas that can be reasonably served by NGP gas). 

Although NGP-produced synthetic gas could conveniently serve the four markets listed above, 
each of these potential CSNG markets can be served by a number of competitive fuels which 
could conceivably threaten the NGP market share. Table 3-9 shows the competitive 
supplementary (i.e., not including domestic natural gas, the primary fuel) gaseous fuels available 
to each of the market areas and their estimated prices. An examination of the table shows that 
Alaskan/Canadian gas and Nuclear Stimulated Natural Gas (assuming the technology proves 
feasible) could be very price competitive with NGP CSNG in its potential market areas. 

(c) Generation and Export of Electric Power. -A third market for NGP coal is electric power 
generation in the NGP. In 1971, 33.8 percent of NGP coal production was consumed in the 
region and 12.7 percent was exported in the form of electricity. 

Power generation utilities in the region have already made their plans for expansions in 
capacity through the early 1980's. As the surplus generating capacity within the Northern Great 
Plains and the transmission capacity determines the abihty of the utilities to export power, the 
supply potential of export power from the Northern Great Plains is essentially fixed through 
about 1985. The Department of the Interior has forecasted further increases in electric 
generation between 1982 and 2000, but utihties have generally not announced specific plant 
sitings beyond the early 1980's. 



"U.S. Energy Outlook," National Petroleum Council, Dec. 1972. 
'This is a much more optimistic forecast of domestic production of both NG and SNG than that made by the 1973 Interior 
forecast. 

III-16 



Table 3-9.— Competitive supplementary gaseous fuels 
(Source: Branch of Natural Gas, Division of Fossil Fuels, USBM) 







Wholesale price 


Market area 


Fuel 


$/million Btu 
(1972 dollars) 


North and South Dakota, 


CSNG* (Western) 


1.10-1.27 


Nebraska, Minnesota, Iowa 


CSNG (Eastern) 


1.24-1.40 




LNGt 


1.35 




NSGt 


0.86-1.05 




North Slope** (into 


1.37 




U.S. West) 






North Slope (into 


1.16 




U.S. Central) 






Alberta Gas 


0.97 


Montana, Wyoming, Colorado, Utah 


CSNG (Western) 


0.91-1.08 




CSNG (Eastern) 


1.34-1.50 




NSG 


0.67-0.86 




North Slope (into 


1.07 




U.S. West) 






Alberta Gas 


0.67 


California, Nevada, Arizona 


CSNG (Western) 


1.04-1.21 




CSNG (Eastern) 


1.52-1.68 




LNG 


1.47 




NSG 


0.80-0.99 




North Slope (into 


0.90 




U.S. West) 






Alberta Gas 


0.50 




Alaska LNG 


1.25 


Washington, Oregon, Idaho 


CSNG (Western) 


0.96-1.13 




CSNG (Eastern) 


1.26-1.42 




LSNG§ 


1.40 




LSNG 


1.47 




NSG 


0.73-0.92 




North Slope (into 


0.87 




U.S. West) 






Alberta Gas 


0.47 




Alaska LNG 


1.22 



*Coal Synthetic Natural Gas. 

'Liquified Natural Gas. 

$ Nuclear Stimulated Natural Gas. 

**Gas from Alaskan North Slope and Canadian Mackenzie Delta. 

§ Liquid Synthetic Natural Gas. 



III-17 



Northern Great Plains coal is currently competitive in some export markets even though 
transportation charges are substantial. It follows that Northern Great Plains coal is in an excellent 
competitive position within the region. Table 3-10 reflects in-region utilities' plans for future 
generating capacity through 1982.*° For South Dakota, which is close to active in-region coal 
mines, and the coal producing states of Montana, Wyoming, and North Dakota, almost all 
additions to total generating capacity will depend on subbituminous coal or lignite. Nebraska, 
which is located further from the coal mining area, will depend on nuclear power for most 
additions to capacity, but will, nevertheless, add approximately 1,850 MW of coal-burning 
capacity. 

(d) Market Conclusions.— \n conclusion, the time frame becomes very important when 
discussing the marketplace for Northern Great Plains coal energy. For the immediate future, 
there is a very clear and broad market for NGP coal. Coal in general— and low sulfur coal in 
particular— is in short supply. Spot sales of bituminous steam coal have reached 40 dollars per 
ton. High sulfur coal, while available, cannot be used because powerplants do not have stack gas 
desulfurization equipment and will not have it for several years. Thus, the high transportation 
costs of NGP coal may be somewhat irrelevant in many markets, especially with the price of oil 
so high. 

The long-term market for NGP coal energy is less certain. There are certainly several factors 
that are distinctly favorable to optimistic market predictions. Chief among these are expectations 
that, without massive new development, coal demand will outstrip supply as U.S. energy demand 
continues to grow while alternative energy sources cannot keep up. The NGP coal would then 
find a large market merely because it is an available and reliable energy source. Also, although 
stack gas desulfurization equipment should be readily available in a few years, a continuation of 
the capital shortage in the electric utility industry will probably discourage installation of this 
capital-intensive equipment. Instead powerplants would tend to use low sulfur fuels-such as NGP 
coal— to meet emission requirements. 

However, circumstances could be substantially different than pictured above. Although several 
energy companies have announced coal gasification plants for the NGP, these plans may be 
stimied by an influx of less expensive Canadian and Arctic gas into potential NGP markets. Given 
an availabihty of capital-perhaps provided by the Federal Government-and sufficient eastern 
and midwestern production, the utihty industry will have the clear option of installing stack gas 



'°1990 for Nebraska. 



Ill- 18 



Table 3-\0.-Northem Great Plains region— projected additions of electric 


generating capacity, 1973-1982* 






Capacity, 




Scheduled 


Plant name and company 


megawatts (MW) 


Fuel type 


operation date 


NORTH DAKOTA: 








Leland Olds 2 (BEPC) 


438 


Lignite 


10/75 


Center 2 (MPCoop) 


435 


Lignite 


5/77 


Lignite 1 (CPA) 


400 


Lignite 


11/78 


Lignite 2 (CPA) 


400 


Lignite 


11/79 


Proposed (BEPC) 


500 


Lignite 


5/79 


Proposed (MDU) 


20 


Oil, gas 


5/80 


Proposed (MDU) 


100 


Lignite 


5/81 


Proposed (NSP) 


800 


Lignite 


5/81 


Proposed (OTPC) 


200 


Lignite 


5/81 


SOUTH DAKOTA: 








Big Stone (OTPC) 


430 


Lignite 


5/75 


Yankton 4 (NWPS) 


6 


Oil 


1/74 


Aberdeen (NWPS) 


20 


Oil, gas 


5/78 


Mitchell (NWPS) 


20 


Oil, gas 


5/79 


Proposed (NWPS) 


20 


Oil, gas 


5/80 


Proposed (NWPS) 


100 


Coal 


5/81 


MONTANA: 








Colstrip 1 (MPC) 


330 


Coal 


7/75 


Colstrip 2 (MPC) 


330 


Coal 


7/76 


Colstrip 3 (MPC) 


700 


Coal 


7/78 


Colstrip 4 (MPC) 


700 


Coal 


7/79 


Libby 1 (Army) 


121 


Hydro 


7/75 


Libby 2 (Army) 


121 


Hydro 


10/75 


Libby 3 (Army) 


121 


Hydro 


1/76 


Libby 4 (Army) 


121 


Hydro 


4/76 


Libby 5 (Army) 


121 


Hydro 


10/82 


WYOMING: 








Dave Johnston (PPL) 


330 


Coal 


1972 


Jim Bridger 1 (IPC) 


500 


Coal 


6/74 


Jim Bridger 2 (PPL) 


500 


Coal 


9/75 


Jim Bridger 3 (PPL) 


500 


Coal 


9/76 


Wyodak (PPL) 


330 


Coal 


5/77 



III-19 



Table 3-10.— Northern Great Plains region— projected additions of electric 
generating capacity, 7975-7952*— Continued 







Capacity, 




Scheduled 


Plant name and 


company 


megawatts (MW) 


Fuel type 


operation date 


NEBRASKA: 










Hebron 1 


(NPPD) 


50 


Gas 


1973 


McCook 1 


(NPPD) 


48 


Gas 


1973 


Sheldon 3 


(NPPD) 


50 


Gas 


1973 


Jones St. 1,2 


(OPPD) 


116 


Gas 


1973 


Cooper 1 


(NPPD) 


778 


Nuclear 


1973 


Ft. Calhoun 1 


(OPPD) 


457 


Nuclear 


1973 


Fremont 


(FDU) 


80 


Gas, coal 


1976 


Gentleman 1 


(NPPD) 


650 


Coal 


1977 


Gentleman 2 


(NPPD) 


600 


Coal 


1980 


Proposed 


(OPPD) 


100 


Gas, oil 


1978 


Proposed 


(OPPD) 


200 


Gas 


1979 


Proposed 


(NPPD) 


200 


Gas 


1980 


Ft. Calhoun 2 


(OPPD) 


900 


Nuclear 


1980 


Cooper 2 


(NPPD) 


1,100 


Nuclear 


1984 


Ft. Calhoun 3 


(OPPD) 


1,100 


Nuclear 


1990 


Otoe County 


(OPPD) 


600 


Coal 


1979 



*Data from Federal Power Commission on 1 0-year future programmed units as furnished by 
utihty regional reliability councils. 



III-20 



desulfurization equipment and burning high sulfur coals. Although the availability of slurry 
pipelines and high desulfurization costs for competing coals would be in its favor, NGP coal may 
still be at a serious price disadvantage in some key markets if the Interagency Coal Task Force's 
predictions are correct. Thus, truly massive coal development in the NGP-on a scale consistent 
with the high Coal Development Profile-will occur only if the factors controUing the markets for 
NGP coal develop in a way distinctly favorable to such development, and this is by no means a 
certainty. 

3-7. Federal and State Actions That Might Affect Development .~ThQ following represents a 
number of areas where Federal and state actions may have a substantial affect on NGP coal 
development: 

a. Mineral leasing policy .—The Federal and State Governments control vast reserves of coal 
in the Northern Great Plains area. Any expansion or contraction of coal leases issued would 
affect coal production. 

b. Import policies. -Coal is the prime energy candidate, through conversion, to make up for 
shortfalls of imported energy supplies such as natural gas and petroleum. By a policy of 
expanding or contracting import quotas, the Federal Government will affect the domestic 
demand for coal. 

c. Environmental quality standards.— Any relaxation of air quahty standards will cause a 
shift from use of NGP coal in some markets to eastern or midwestem coal to meet electric 
generating requirements. Stricter reclamation and rehabilitation standards for surface mining 
could shift preference from surface-mined coal to underground coal. 

d. Research and development support.— Coal demand fluctuates accordingly to the 
availability, size, and use of research and development funds. For instance, if federally funded 
nuclear and solar energy programs result in technological advances, demand for coal will be 
reduced. If, however, funds are provided for development of coal gasification and hquefaction 
techniques and these techniques are developed, demand for coal will increase providing the 
conversion cost is competitive. 

e. State policies. -States will also play an important role in determining the rate and extent 
of coal development in the Northern Great Plains. The amount of state taxes imposed on coal 
development facihties and on the product will influence its price and competitive position in 
the market place. State plant siting acts and the allocation of water resources will also 



III-21 



influence the level and type of coal development. As an example, Montana and North Dakota 

have taken action to discourage the construction of coal conversion plants on federally leased 

lands. 

3-8. Method Used to Assess Range of Potential Changes.— The 1973 Department of the 
Interior consumption forecast described in the previous section was used to construct a CDP 
(Coal Development Profile) for the Northern Great Plains. The rate of coal production, which is " 
described in the intermediate CDP (designated CDP II), is consistent with the national energy \ 
consumption and production forecast. Coal Development Profile II represents an estimate of the I 
NGP coal production rate for export, in-region power generation, electrical export, and synthetic ! 
natural gas production consistent with the Interior forecast. Explicitly assumed is that sulfur 
dioxide emission control devices will be available for installation in 1980. 

! 
I 

Clearly, other rates of consumption are possible. Therefore, two additional CDP's were j 
postulated: a lower rate of coal production (CDP I) sufficient to meet existing contractual 
agreements and increases in regional demand for coal, and a higher rate of coal production (CDP I 
III) based on the maximum contribution that NGP coal might reasonably be expected to make in ; 
alleviating shortages in the supply of imported oil and gas and domestic nuclear electric j 
generation. 

Rates and types of consumption may be impacted by alternate land use pohcies. Some of the 
alternatives that are available are discussed in the conservation section 3-4. 

(a) Rationale for Use.— Each CDP postulates an amount of coal that could be produced, and 
why; where mines, power generation, and SNG facilities could be sited; how much acreage would 
then be disturbed, and where; how much water would be required; and how many jobs would be 
created. Each CDP characterizes a development situation in sufficient detail to become the basis 
for analysis of impacts and issues. 

In each CDP, the coal produced is used in a number of ways. These include electric generation 
for in-region consumption, electric generation for export, coal export, and synthetic natural gas 
production. 

Electric generation for in-region consumption does not vary between CDP's and electric 
generation for export varies only in the low CDP I after 1985. The low CDP I has no synthetic 
natural gas production while the intermediate CDP II has synthetic natural gas production in 
1985 and the high CDP III in 1980. The level of coal exports varies significantly between CDP's. 
This detail is summarized graphically in figure 3-10. 

III-22 




^ i m ( I 1 .1 1 ^ 1 < yr ' 'i L '- r " . ' " I ^t 1 ' 



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The employment generated by this development plus the water and land requirements 
associated with each CDP are shown in table 3-11. 

The low rate (CDP I) represents the minimum reasonable rate of coal production since it 
includes only those increases in production which are already guaranteed (that is, secured by 
signed long-term contracts) or highly probable (that is, supplying increased regional 
thermal-electric powerplants). 

The higher rate CDP III is based upon the following specific assumed shortfalls below the 
projected levels of national energy supplies: imported petroleum— 3 mbl/day (million barrels per 
day) in 1985, 5 mbl/day in 2000; Canadian natural gas- 1,000 bcf/yr (billion cubic feet per year) 
in 1980, 2,100 bcf/yr in 1985, and 4,000 bcf/yr in 2000; nuclear generating capacity 20,000 MW 
in 1985 and 240,000 MW in 2000. The coal production estimates for this CDP are based upon 
significant exports to the largest conceivable market area that NGP coal might serve in order to 
make up a portion of this shortfall. Because of current trends toward increasing energy use and 
the increasing difficulty of importing energy, it is prudent to consider the possibility that this 
maximum rate of production of NGP coal may be necessary. This higher CDP III probably 
represents maximum production because of likely shortages of transportation facilities, capital, 
and skilled manpower in the region, and the high cost of shipping coal long distances. 

This method of analysis was chosen since it provides a means for establishing realistic 
minimum and maximum rates of possible coal production, as well as a middle rate, and relating 
the resultant production levels to both the national energy situation and the impact on the 
region. This permits a comprehensive identification and analysis of impact. It does not establish a 
plan or alternative plans for coal production for the area. 

(b) Siting of Mines and Plants.-The projection of mine sites for various CDP's was based upon 
coal demand, identified by states in the Northern Great Plains, as estimated by the National 
Energy Considerations Work Group. The Minerals Work Group first identified the geographical 
locations of the so-called "strippable" coal reserves in the study area. It was assumed that the 
optimum (or "unit") sizes of powerplants ranged from 1,025 to 1,250 MW (megawatts) and 
required from 3.5 to 6.8 million tons of coal per year (dependent upon the power produced and 
the BTU content of the coal which ranged, in the estimates, from 9,650 to 6,000 Btu/lb)' ' . It 
was assumed that the optimum size for a coal gasification facility was 250 MCFD (million cubic 



11 12 

Assumes 65 x 10 Btu per year from coal per 1,000 MW of electrical capacity. 



III-23 



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III-24 



feet/day) which required from 7.1 to 1 1.5 million tons of coal per year (based again, on a range 
of 9,650 to 6,000 Btu/lb)' ^ . It was assumed that export mines would produce about 10 million 
tons per year; however, a few mines from 4 to 9 million tons per year production were sited. It 
was further assumed that the life of a coal natural gas conversion'plant would be 20 to 35 years 
(powerplants 35 years). Thus, a total coal requirement for a mine was derived. 

Based then on the location of mines, the indicated interest of mining companies and 
"conversion" companies in other sites, the general quality (BTU content) and thickness of the 
coal, and a cursory evaluation of coal/land ownership, mines, and therefore, mine-mouth plants 
were sited. First priority was given to those sites for which feasibility studies or actual 
construction plans had been announced. Proximity of water sources and gas pipelines was not 
directly considered as a constraint although proximity to drainage channels was considered. 
Allowances were not made for improved conversion efficiencies. Export mines were sited with 
some consideration of transportation routes but no consideration of specific destinations for the 
exported coal. In all siting projections, no special consideration was given to minimizing potential 
adverse social and environmental impacts. 

(c) Importance of NGP Coal by CDP and by both tonnage and as a percentage of national 
energy consumption. 

Table 3-\2.— NGP coal production 





(Million short tons) 








CDP 


1971 


1975 


1980 


1985 


2000 


Low(l) 

Intermediate (II) 
High (III) 


21.3 
21.3 
21.3 


52 
52 
52 




91 
107 
160 


108 

192 
382 


144 
362 

977 



CDP 


(Percent o 
1971 


f national energ 
1975 


y consumption 
1980 


) 

1985 


2000 


Low (I) 

Intermediate (II) 
High (III) 


0.46 
.46 
.46 


0.97 
.97 
.97 


1.42 
1.67 
2.50 


1.39 

2.47 
4.91 


1.13 

2.83 
7.64 



12 12 

Assumes l37,5 x 10 Btu per year from coal per 250 x 106 million cubic feet per day gas output. 



III-25 



Table 3-12 reflects an increasing percentage contribution by NGP coal to national energy 
supply in the intermediate and high CDP's, but a decreasing contribution after 1980 in the low 
CDP' ^ . The CDP's are based on national energy consumption of 191.9 quadrillion Btu's in 2000. 
The CEQ (Council on Environmental Quality) has established 121 quadrilHon Btu's as an 
expected demand goal for year 2000 energy consumption. The 14.7 quadrilhon Btu's which NGP 
coal would contribute in 2000 in the high CDP represents about one-fifth of the energy saved 
under the CEQ goal. If their goal is achieved, some reduction in NGP coal production is likely. 

Table 3-13 gives state production detail reflecting some concentration of activity in Wyoming 
and Montana. 

Table 3-\3.— Coal production from each NGP state for each CDP 







(Million short tons) 




1971 


1975 


1980 


1985 


2000 


Montana 














Low (CDP I) 




7.1 


20 


34 


39 


58 


Intermediate (CDP 


ID 


7.1 


20 


41 


75 


133 


High (CDP III) 




7.1 


20 


64 


153 


393 


Wyoming 














Low (CDP I) 




8.1 


23 


37 


43 


55 


Intermediate (CDP 


II) 


8.1 


23 


47 


73 


110 


High (CDP III) 




8.1 


23 


54 


153 


386 


North Dakota 














Low (CDP I) 




6.1 


9 


19 


26 


33 


Intermediate (CDP 


ID 


6.1 


9 


19 


44 


119 


High (CDP III) 




6.1 


9 


42 


76 


198 



(d) Current Outlook in Relation to the CDP's.-The CDP coal extraction rates were projected 
in early 1973 by the Energy Work Group. Actual production plans by industry were changing 
substantially and have continued to change. To determine the latest industry projections, 
Montana, North Dakota, and Wyoming updated their data for a 1980 target date as shown on the 
following: 



For the year 2000, in the intermediate CDP, national coal consumption would be 16.4 percent of total energy 
consumption. In the low CDP, national coal consumption would be 16-16.4 percent of total energy consumption. In the high 
CDP, national coal consumption would be over 21.2 percent of total energy consumption, the exact amount depending upon the 
response of non-NGP coal to assumed shortages. 

III-26 



Production rates, 1980 
(Million tons per year) 

CDP I Estimate 91 

CDF II Estimate 107 

Actual Industry Expectation 143 

CDP III Estimate 160 



The actual estimate of coal production is based on contracts and the best estimates of 
individual companies for export, power generation, and synthetic natural gas production. It 
includes one 10 MT/yr (million ton per year) mine for one CSNG plant in North Dakota that is 
expected to be in operation by 1979-80. 

The 143 MT/yr 1980 estimate is 1 1 percent below the CDP III estimate and 34 percent above 
the CDP II estimate. The CDP II was projected by the Energy Work Group in early 1973 to be 
the most probable production level. The 143 MT/yr current industry expectation is greater and 
indicates there has been more interest in developing NGP coal than anticipated. The production 
that actually takes place, however, could vary significantly from either the CDP estimates or 
actual industry expectations. 



III-27 



PART IV-LAND, WATER, AND AIR RESOURCES 
OF THE NORTHERN GREAT PLAINS 

1 . Land Resources 

4-1. Introduction .-The NGP is "Big-Sky Country." Much of it is so open and rolling that in 
Dunn County, North Dakota, two large hills rising 600 feet above the plains are referred to as 
mountains. The Northern Great Plains stretch nearly 350 miles north to south-from Canada on 
the north to central South Dakota on the south— and almost 450 miles east and west from central 
North Dakota to Montana (plate 9). 

In the rolling grass and brush-covered plains of the eastern part of the region, a lone tree is an 
outstanding feature. A low butte or a hazy mountain range in the distance is an attraction. It is a 
country of wind. Wind that quickly dries soils and drifts snow during the blizzardy winters. It is a 
dry country; only 2 percent is covered by the waters of lakes and streams. Annual precipitation 
normally ranges from 10 to 26 inches. Much of plains region only receives 12 to 16 inches of 
precipitation in a year. Thomwaite' said in 1941 that out of 37 years, 1 had been humid, 1 moist 
subhumid, 5 dry subhumid, 25 semiarid, and 5 arid. The arid and some of the semiarid years are 
too dry to reclaim disturbed land without irrigation. 

The NGP is a land of big cattle-and-wheat ranches. Ward County, North Dakota, has the 
smallest average size farm, 815 acres. Natrona County, Wyoming, has the largest, 1 1,105 acres. 
Farms and ranches have to be large because it takes a great number of acres to produce enough to 
support a family. Seventy percent of the area is pasture and range; 26 percent is cultivated for 
wheat, barley, flax, rye, oats, corn, alfalfa, and sugar beets, but "wheat-and-meat" are the main 
products. In 1971, a little less than one-twelfth of all U.S. wheat was produced in this region, and 
less than 3 percent of the land is irrigated. 

There are few people, only 4.4 per square mile, compared with Iowa and Ohio having 52 and 
263 persons per square mile, respectively. Many have a love for the land. A frontier ethic of 
"stand on your own two feet" is still strong. There are Indians: the Sioux, the Northern 
Cheyenne, Crow, Assiniboine, Gros Ventre. The six major reservations include 5.6 million acres 
or 6.4 percent of the land. About 25,000 individuals live on these reservations resulting in a 
density of only 2.9 persons per square mile. 



Even though there are relatively few people in the NGP urban land, consumption is already 
affecting the NGP. Between 1958 and 1967, the intensively built-up urban area increased 27 
percent to 1.2 milUon acres. 

The transportation net is the only development spread across the whole NGP. There are 5,440 
miles of major electric transmission lines, 88,565 miles of rural and municipal roads, 5,000 miles 
of railroad lines, 7,421 miles of oil and gas pipelines, and 100 public airports. 

(a) Resources of National Importance .—Before the coming of the white man, the Northern 
Great Plains were controlled by a mobile and powerful Indian people. The first white men who 
came to exploit their lands were the fur trappers and traders, soon after came the pioneers 
traversing the Oregon Trail. From the south came the cowboys herding thousands of head of 
longhoms. There was a time of triumph and defeat for both Indian and non-Indians alike. There 
was Sitting Bull and Crazy Horse and the Battle of the Little Bighorn. Open-range ranching 
started and then faltered in the terrible winter of 1886-87 and began again. As the cattle industry 
grew and the miners came to dig for gold, the Indians' hold on the land was wrested away from 
them and the basic culture and lifestyle that exists in the Northern Great Plains was established. 

The rivers of the region are its' life lines. Along these ranches are built, crops are grown, and 
roads and railways laid down. Rivers are also the key to the varied and abundant wildlife, fishing, 
and variety in the scenery. Segments of Clark's Fork of the Yellowstone, the Yellowstone, the 
Missouri, and the Little Missouri are being considered for national wild, scenic, or recreation river 
status. The Upper Yellowstone and Sand Creek in Crook County, Wyoming, are two of this 
country's few remaining blue-ribbon trout streams. 

Some 2.5 million acres of the 92 million acres that comprise the Northern Great Plains study 
area are "wild lands" some of which have potential for inclusion in the National Wilderness 
System. Most are already Federally owned and they depict a wide variety of topography and 
vegetation. Five areas are being considered for inclusion in the Wilderness System. They are 
portions of the Big Horn Mountains, Theodore Roosevelt National Memorial Park, Little 
Missouri, Charlie Russell National Wildlife Refuge, and Lost Wood-Medicine Lake Refuges. 
Nearly 3 million acres adjacent to the Northern Great Plains study area in the Missouri Basin may 
soon be proposed by Congress as "Wildnemess Areas." 

The black-footed ferret, a rare predator of the prairie dog, and the whooping crane seasonally 
inhabit the region. Although they are possibly the best known of all the endangered species in the 



IV-2 



United States, others are found in the NGP. The American peregrine falcon, the prairie falcon, 
the tule white-fronted goose, the spotted bass, the American osprey, the prairie pigeon hawk, the 
mountain plover, the long-billed curlew, the western burrowing owl, the northern swift fox, and 
the northern greater prairie chicken either stop by on annual migrations or live there throughout 
the year. 

Big game is another resource of national significance. Before 1800, there were an estimated 
700,000 antelope in South Dakota as well as millions of buffalo. Lewis and Clark first met the 
grizzly here and alerted the world to his existence. They called him Ursus honibilis, the horrible 
bear. Mule deer, white-tailed deer, and black bears abound, and Big Horn sheep are still found in 
the more inaccessible areas. 

Hunting is a part of the NGP culture with many nonresidents coming into the region to take 
part in these activities. In 1970, there were over 90,000 nonresident hunters licensed to hunt in 
Montana and Wyoming. 

The quality of antelope hunting is outstanding. Hunters also come for deer and elk, sheep, sage 
grouse, and other upland birds and waterfowl. The high quality of hunting found in the NGP is 
directly related to the relatively low pressure of hunting on game populations and the thousands 
of acres of undeveloped land. 

Other kinds of recreationists visit the NGP as they move to areas on its fringes, such as 
Yellowstone Park or the Black Hills. The Badlands areas, for example, in Theodore Roosevelt 
National Park, are a unique scenic feature found mostly along river breaks. 

All of these resources are of importance to many more people than just those of the region. 
They are national resources, and many are the last vestiges of what this country once was. 

(b) Resources of Regional Importance .—AW of the resources of the Northern Great Plains are 
important to the people who live there. They either create the basic productivity, from which 
their livelihood is derived, or they add to that complex mixture of history, attitudes, and 
landscape appearance that results in their life style. 

The resources critical to the ranching industry are the hay meadows, irrigation water for the 
meadows, and the dry grazing land. In North Dakota, dryland hay production areas are also 
important. To the farmer, of critical importance are irrigation water and cropland areas. 

The livelihood of a significant number of residents is derived from production of nonrenewable 
resources such as coal, gas, oil, and uranium. Without these resources and their production these 
peoples' livelihood is lost. 

IV-3 



The recreation-tourism is a basic industry of the NGP. It provides an outlet for 
resident-recreationists as well as tourists. Of prime importance to this industry are the relatively 
unaltered rivers and adjoining landscape, the surrounding mountains, and the rich wildlife 
resources. The same resources that create the recreation-tourism industry are just as significant to 
the residents because they help to create the overall atmosphere. The relatively undisturbed open 
landscapes, clear and free-flowing rivers, and the clean air are very important. 

Coal development and the associated growth in population would impact the natural resources 
of the NGP, and therefore the life and livelihood of the people, both of the region and visitors. 
The potential impacts of coal development are discussed in subsection 4-2(c). 

The first aspect of coal development which will be discussed is the impact on land resources 
(sec. 4-2). Of special concern are the ecosystems that may be disturbed-the potential for 
restoration. 

The second aspect of coal development which might have substantial impact is the use of water 
for coal conversion activities; such as electric power generation or coal gasification plants and the 
increased domestic use of water. Questions concerning the use of water by coal development and 
their impacts on surface and ground water are discussed in section entitled "Water Resources." 

A third aspect of coal development is the air pollution that might result from the operation of 
electric generation or gasification plants and associated activities. The possible extent and impact 
of air pollution is addressed in the section on "Air Resources" (sec. 4-12). 

4-2. Land Resources.— The impact of potential coal development on the land resources of the 
Northern Great Plains has raised issues of national as well as regional interest. The most obvious 
impacts on land resources will come from surface mining, however, there are many other related 
activities that will also impact land. Some of the issues related to this development include: 

—What kinds of ecosystems are found in the Northern Great Plains and how will coal 
development affect them? 

—How much land will coal development disturb? 

—Can the land be restored after mining is completed? 

—What are the long term as well as the short term losses? 

(a) Ecosystems of the NGP.— There are six broad ecosystem catagories in the NGP area. These 
are individually tabulated below to provide a perspective for more detailed consideration of the 
areas land resources. 



lV-4 



The ecosystem categories are:* 



System 







System in percent 




System in percent 


of strippable 




of study area 


coal acreage 


Grasslands 


67 


58 


Streambottoms 


4 


2.1 


Badlands 


3.3 


1.2 


Brushlands 


17 


28 


Ponderosa Pine 


4 


10.5 


Mountains 


4 





Other 


0.7 


0.2 



*Text combines the following ecosystems as shown on plate 7. Grasslands include: short-grass, midshort grass, midgrass, 
grassland sandsage, midtall grass, foothills grassland, and prairie oak savanna. Brushlands include: grassland-sagebrush and 
sagebrush-steppe. Mountains include: black hills pine, Douglas-fir forest, pine-Douglas fir, and subalpine. No ecosystems are 
combined in badlands and ponderosa pine. Flood plains are named streambottoms in text to incorporate closely associated 
adjoining landscape rather than just the flood plains; however, percentages shown on plate 7 refer only to the acreages in the 
floodplains. 



Sixteen ecosystems were used in the more detailed work group analyses as shown on plate 7. 
These were condensed into the above six categories for ease of analysis. 

(1) Grasslands. —Sixty -seven percent of the NGP is grassland which is underlaid by 58 
percent of the strippable coal acreage. Precipitation ranges from 18 inches in central North 
Dakota to 10-14 inches in southeastern Montana and northeastern Wyoming. 

In the wetter North Dakota area, unplowed native grass is dense and ranges from knee high 
to waist high. In the drier areas of southeastern Montana and northeastern Wyoming, it is a 
little more than ankle deep and is mostly blue grama grass and buffalo grass. Much of the 
knee-high grasslands of northeastern Montana and northwestern North Dakota have been 
plowed and converted into farms. In the short-grass areas of southeast Montana and northeast 
Wyoming, only about 10 percent of the land is farmed. Throughout the grasslands, if the land 
isn't farmed it is grazed by livestock and some wildlife. 

Throughout the grassland there are also forbs (herbs) that mix the bright colors of their 
blossoms with the various shades of green. There are some shrubs, more as one goes from 
wetter to drier areas. There is big sagebrush for which the West is famous. Wildlife include 
antelope, jackrabbits, paririe dogs, black-footed ferrets, meadowlarks, prairie chickens, and 
birds of prey. Around cropland are ring-neck pheasant and red fox. The land and pothole 
country of northwestern North Dakota and northeastern Montana is part of the North 
American "duck factory." The endangered whooping crane passes through here annually. 



IV-5 



Most of the grassland is rolling open country and because they are so rare and seen for such 
great distances, every hill must have a name— from Smokey Finger to Horse Nose Buttes. 

Wildhfe is the most important recreational resource of the grasslands. The big game, birds, 
and fish attract hunters, fishermen, and wildlife observers from all over the United States as 
well as serving as recreation (and a food source) for people of the NGP. 

The grasslands are also the site of many historic attractions ranging from Custer's Battlefield 
to hundreds of areas where archeological remnants of Indian hfe are found. 

Rehabilitation of most grasslands will be easier than other areas since topography is gentle 
and soils are fairly well developed. Rehabilitation of this ecosystem is especially important 
since so much mining will take place there. 

(2) Streambottoms.— About 4 percent of the study area is in streambottoms which is 
underlaid by 2.1 percent of the strippable coal acreage. 

The rivers, flood plains, and adjoining landscapes are "the rivers of life" for the region. 
Historically, and at present, most human activity radiates outward from the flood plains. 
Places like Billings, Bismarck, Sheridan, Rapid City, Casper, and Douglas are located in or 
adjoining the flood plains. Flood plains, being few in number in the NGP, are vitally important 
wherever they are found. They are the principal land form that breaks up the relatively 
monotonous adjoining open rolling country, giving it a unique character and identity. They 
pass through the grasslands, badlands, brushlands, and timberlands. 

Typical streambottom vegetation includes cottonwood, willow, green ash, box elder, 
greasewood, salt grass, and western wheat grass. It is the home of furbearing animals and other 
wildlife such as mule deer, white-tailed deer, red fox, and numerous species of birds. 
Streambottoms are natural hazard areas, extremely susceptable to disruption. Stable stream 
banks and most of the adjoining flood-plain landscape would be nearly impossible to 
reconstruct. Mining in the streambottoms could disrupt the entire ecosystem for many miles 
upstream as well as downstream. The loss of vegetation from streambottoms would make the 
adjacent uplands less valuable for wildlife and domestic stock. Wildlife ranging over many miles 
often depends on the narrow thread of streambottom. Revegetation of the bottoms, under 
correct procedures, would be relatively easy because of the shallow ground water. However, 
great danger lies in disturbing this area because of the proximity of the flowing water and 
because of the dangers created from disturbing the natural flood-retarding character of the 
flood plain. 

IV-6 



The streambottom ecosystem is a complicated and dynamic environment where the 
seemingly different aquatic and terrestrial systems join to provide an environment with a 
diversity not found anywhere else in the region. The purely aquatic environment and the 
riparian habitat are inextricably joined and this dynamic interdependence of the two 
environments is expressed in many ways. The plants and animals that live in the streams 
depend on a continuing supply of nutrients that are washed from the adjacent landscape, 
consequently their habitat may be severely degraded by run-off of excessive nutrients or 
sediment. Many insects and other invertebrates that spend their adult phases on land and are a 
food source for the small mammals and birds living on the flood plain, spend their juvenile 
phases in the stream where they are a food base for fish which in turn are preyed upon by 
other animals. Bushes and trees stabihze banks and provide refuge for small fish and in turn 
derive the moisture they require for growth and reproduction. Bacterial activity in the streams 
purifies the water, benefiting the many animals that rely upon it. Because of the many 
chemical and biological processes associated with a stream ecosystem, it is tolerant of a wide 
variation of conditions. However, if one system becomes inoperable it can have cascading 
impacts which destroy parts of, and in some cases, the entire natural community. 

Coal development may change streams by increasing the TDS (total dissolved solids), BOD 
(biochemical oxygen demand), and temperature. Significant deviations from the normal range 
of any one of these factors could have deleterious effects on aquatic animals. It must be 
recognized that the effect of a change will depend on the total spectrum of biochemical and 
physical conditions existing at the time and not on one factor alone. For instance, as 
temperature rises, the metaboHc rate of cold-blooded animals increase and their biological 
oxygen demand increases. Simultaneously, as temperature rises, the amount of oxygen that is 
naturally contained in a given volume of water is decreased so at the very time more oxygen is 
required, less is available. This then, exposes the animal to two stresses, one directly 
attributable to increased temperature, the other indirectly to reduced oxygen. As this simple 
example illustrates, the changes that may occur due to TDS and BOD cannot be considered 
separately but must be integrated before impacts can be determined. Such an integration is 
beyond the scope of this study and when conducted is necessarily limited to specific sites 
because of the complex nature of such a study and the variation between sites. 



IV-7 



The streams in the Northern Great Plains at their headwaters are steep gradient streams 
characterized by low water temperatures, TDS, sediment loads, and high oxygen 
concentrations. Their headwaters are trout water. They are clear and support insect larvae with 
high oxygen demands. As the steams traverse the plains, they begin changing. Their gradient 
decreases and they flow slower, eventually meandering across large bits of real estate creating 
large flood plains. The TDS and sediment loads as well as nutrient levels increase, summer 
temperatures are higher, and dissolved oxygen content is reduced, sometimes to critical levels. 

The aquatic species begin to change. The gravel beds become caked with sediment. Trout are 
unable to spawn here. The insect larvae that live here are those that tolerate lower dissolved 
oxygen concentrations and higher temperatures. Channel catfish and sauger become the 
dominant species. 

If coal development results in increased water temperatures, TDS, BOD, and sediment loads, 
we can expect the trout and the species associated with it to retreat towards the headwaters 
while many of the species now living in the lower portions of the streams will invade the areas 
vacated by the trout. 

(3) Badlands.— In the study area, 3.3 percent is referred to as badlands and is underlaid by 
1.2 percent of the strippable coal acreage. 

Badlands occur mostly along river courses: the lower Powder River where it adjoins the 
Yellowstone, south slopes along the upper Tongue, and in a belt 5 to 25 miles wide and over 
200 miles long along the Little Missouri in North Dakota. There are large badland areas along 
the Missouri in the Charlie Russell National Wildlife Refuge. 

Badlands get their name from the raw, bare, rapidly eroding, usually south-facing slopes of 
exposed layers of shale, lignite, and sandstone. In the gentler rolling parts and in pockets along 
deep, steep-sided coulees, a shallow soil supports plant growth, grazing, and even some small 
areas of dryland farms. Precipitation is only 10 to 14 inches, which makes a harsh environment 
even less hospitable. 

Typical vegetation included shadscale, greasewood, and saltgrass on the thin soils. On better 
soils, big sagebrush, fringe sagebrush, rabbitbrush, bluebunch wheatgrasses, and Rocky 
Mountain juniper trees are common. 

Wildlife includes mule deer, prairie rattlesnakes, lizards, rabbits, and a myriad of other 
prairie animals. Wild turkeys have been reintroduced and are doing well. In total, the badlands, 
like the streambottoms, are critically important to wildlife, vegetation, and recreation. 

IV-8 



Because of the crazy -quilt mixture of raw slopes and strips, patches and flats of shallow soil, 
and the mixtures of reds, whites, yellows, and grays from clays, bentonites, and brick red 
scoria, the badlands are extremely fragile. They cannot be restored to anything near their 
original condition. To grow plants would probably require importing cover soil and even then 
so little is known about it that the results are unpredictable. To recreate the colors would take 
more paint than could be afforded. In any case, the stark, rare beauty of intricately woven 
steep-sided ridges and coulees could not be duplicated and disturbance would greately increase 
erosion. The badlands are likely to be an increasingly important recreation resource as interest 
in wilderness hiking, camping, and nature study increases. 

(4) Brush lands.- Approximately 17 percent of the study area is brushland and is underlaid 
by 28 percent of the strippable coal acreage. 

Part of the southernmost portion of the study area in Montana and most of northeastern 
Wyoming is brushland. This area receives some 10 to 14 inches of precipitation per year. The 
soils are generally lighter with more silty and loamy textures than in the grasslands. The grasses 
are much the same species as in the grasslands with some of the taller ones missing. Bluebunch 
wheatgrass is a major grass species. Saltgrass, shadscale, and greasewojd indicate saline soils. 
Big sagebrush is a dominant woody species. It is an absolute necessity for sage grouse and 
generally so for antelope. Antelope and sage grouse are the most abundant game species in this 
ecosystem. Both antelope and sage grouse are nearly unique to the Northern Plains and both 
attract many hunters. Sage grouse are the second largest upland game bird following wild 
turkey. Mule deer and antelope winter ranges are located in the brushland along the foothills. 

Less than 5 percent of the brushlands are in cropland and less than half the cropland is 
irrigated. Most of the rest of the brushlands is grazed by domestic livestock. Most of the year 
the land looks dry and desolate. Because so much of this type of ecosystem is open and rolling, 
power lines and plants would be visible for long distances. Most of the surface material over 
coal is sahne or alkaline and needs special handling. Techniques for properly handling this 
material remain to be developed. 

Many native plants would be useful in revegetation of strip-mined land. Because of the 
usually dry climate and frequency of drought, revegetation will take more effort here than in 
much of the grassland. 

(5) Ponderosa pine— Four percent of the study area is ponderosa pine and is underlaid by 
10.5 percent of the strippable coal acreage. 

IV-9 



The Ponderosa pine forest is the most common and driest of the forests of the Northern ' 

Great Plains. Scattered throughout eastern Montana, northeastern Wyoming, and the western 1 

Dakotas, it receives about 12 to 17 inches of precipitation annually. Ponderosa usually occurs ! 
on the moister north slopes of steep topography, crests of hills, ridges, and rimrock. 

Most of the previously mentioned grass species are found in the understory. In addition, | 
western snowberry occurs here in quantity. It is also an important wildlife area. Mule deer are 
at home as well as many species of birds of prey. The pine forest is much more complicated 

than the brushlands or grasslands because the trees provide diverse habitats. A large share of i 

the shallow ground water is recharged from aquifers surfacing in the ponderosa pine type. I 

(6) Mountains.— About 4 percent of the study area is mountainous and has no underlying 

coal seams. ,| 

These areas include the wetter pine forest of the Black Hills, Douglas firs, and the subalpine \ 

areas of the higher mountains. These receive more precipitation than any area of the Northern \ 

Great Plains, some 18 to 26 inches. The Black Hills and the Big Horn Mountains provide the 

principal backdrops for the Northern Great Plains region. Although they do not contain coal, \ 

they are vitally important to the region and national recreation scene. Coal development J 

activity out on the more open country would affect these regions, as a result of human i 

immigration, more powerplants, rights-of-way, air pollution, and possibly water diversion \ 

structures. | 

(b) Rehabilitation Potential of the NGP Surface Minable Land.-ThQ successful rehabilitation I 

of the ecosystem of the Northern Great Plains will depend on conditions that exist at the I 

restoration site. Factors to be considered are precipitation, soils, topography, complexity of the | 

premine vegetation and projected use of the lands. Central to all rehabilitation efforts is ' 

re-introduction of vegetation to the disturbed land. Important factors controlling the potential j 

i 

for revegetating various land types include: (1) amount and distribution of precipitation, (2) soil ] 

productivity and stabihty, and (3) suitability and availability of plants for rehabilitation ■ 

purposes. An examination of these three factors shows that the surface minable lands of the NGP ] 

occur in 7 annual precipitation zones, 1 7 soil associations, and 9 broad vegetative types. | 

Of all possible combinations of these factors 86 occur in the Northern Great Plains, thus, the 

surface minable lands can be divided into 86 different kinds of land each with its own ,; 

revegetation-potential characteristics. Most combinations are found in more than one location, < 

,1 
I 

\ 

IV-10 ■ 



there are a total of 146 areas which have been denoted as rehabilitation-response units (RRU) 
(plate 8). It has been assumed that, regardless of location, rehabilitation response units that have 
the same soil-vegetation-precipitation identifications should have similar responses to 
rehabihtation efforts. For purposes of this study it was assumed that overburden and topographic 
characteristics would not constrain vegetation. 

Rehabilitation research has been initiated on 1 5 surface coal mines and three large bentonite 
mines in the NGP. These mines are found on only 14 of the 86 different RRU. Fortunately they 
are distributed over a sufficiently varied range of RRU to allow some interpolation of results. A 
detailed examination of these sites plus an analysis of the rehabilitation potential of each of the 
86 RRU is included in the Surface Resources Work Group Report. Plate 3 graphically presents 
these units and divides them into areas of poor, fair, or good potential for rehabilitation. 

This study reveals that Mercer and Oliver counties in North Dakota have a much higher 
potential for successful rehabilitation than do those in other sample counties (sample counties 
shown on plate 9); soils are more productive, vegetation types more suitable, and precipitation 
higher than in the other sample areas. Rosebud County, Montana, has the next best potential, 
followed by Bighorn County, Montana and Campbell County, Wyoming. The poorest 
rehabihtation potential recorded for Campbell County results from a combination of poor 
productive soils, vegetation types that have the fewest suitable and available species and the 
lowest precipitation in the NGP coal province. 

Although general conclusions such as those drawn above are helpful to compare differences 
between areas within the NGP region it must be noted that relatively little experimentation and 
research have been directed to the problem of rehabihtating lands being mined for coal in the 
NGP. Perhaps the most important single point emerging from this study is that the potential for 
rehabihtating surface-mined land in the NGP is extremely site-specific. The general rehabilitation 
potential can be judged on the basis of climatic soil and vegetation components but each site will 
also have its particular microclimate in terms of specific physiographic, biotic, and hydrologic 
components. These macrosite and microsite components, as well as the measures employed to 
effect revegetation inherently impose constriants on and limitations to successful rehabilitation 
of surface mined land in the NGP. 

Although plate 3 rates lands for their rehabilitation potential, it should be understood that it 
refers to potentials for reestablishing vegetation and not to potentials for rehabilitating 



IV- 1 



topography and shallow aquifers to predisturbance characteristics. Areas such as the badlands, 
streambottoms, and adjoining breaks and much of the ponderosa ecosystems have topographic 
characteristics that prevent re-creation to predisturbance conditions. Also, the ratings are relative 
to each other only. No lands in the Northern Great Plains have been revegetated for sufficient 
time or with a sufficient variety of native species to determine potentials for success. Indications 
are, however, that the best potential for success will be in the "good" areas, somewhat less 
potential in the "fair" areas, and the poorest potential in the "poor" areas as shown on plate 3. 
Within these broad rating areas, potentials will still be site-specific, depending on slope, soil, and 
microclimate characteristics. 

Estimates of direct onsite rehabilitation costs range from approximately $700 to $1,800 per 
acre, depending upon the locations and the problems encountered. The rehabilitation costs 
shown in table 4-1 include those of land shaping, seedbed preparation, seeding, fertilizing, soil 
amendments, water control on slopes, mulching, sediment control in detention basins, shrub or 
tree planting, topsoil replacement, and in some instances outsite irrigation facilities. The largest 
expenses are usually those of shaping the land and replacing topsoil. Considering the relatively 
great tonnages of coal that will be mined per acre in the Northern Great Plains, the cost of 
revegetation can be accomplished without adding more than a few cents per ton (table 4-1). 

Table 4-1.— Onsite rehabilitation costs 



Coal seam 

thickness 

ft. 


At a minimum 
costof $700/acre 
cost per ton, cents 


At a maximum 

cost of $l,800/acre 

cost per ton, cents 


10 

30 

150 


4.35 
1.45 
0.23 


11.16 

3.72 
0.74 



This does not include the cost of water and it could be relatively high. In a drought year or 
period of years when only one-fourth of the average precipitation were received, 9 inches of 
irrigation water would need to be added to assure the minimum of 1 2 inches for establishing grass 
species. If water is available from a Federal aqueduct system, it would cost $38 to $325 per 
acre-foot. If each acre needed to be irrigated for one year it would add $28 to $244 per acre to 
the revegetation expense. If water had to be applied 2 years in succession, it would add $56 to 
$488 respectively. If 12 inches had to be added to assure the minimum of 16 inches required for 
establishing large shrub and tree species, the per acre costs for irrigation would be increased by 



IV-12 



$38 to $325 per acre and for watering 2 years by $76 to $750 per acre. These costs would be 
added to the $700 to $1,800 per acre revegetation costs. Although irrigation may be needed only 
occasionally, the expense of the water system may have to be incurred to insure sufficient water 
if needed. 

To better understand the problems associated with revegetation of these lands and to 
determine the potential of restoring surface-mined lands to biological productivity research in 
several areas is needed. Some of these areas are: 

(1) Analysis and evaluation of chemical and physical characteristics of the existing soils of 
geologic overburden materials in relation to their suitability for revegetation purposes; 

(2) Development of methods and techniques for creating favorable microbiological activity 
in surface-mine spoils; 

(3) Evaluation of the physical and chemical quality of surface and subsurface runoff water 
from mine spoils under different rehabihtation treatments; 

(4) Testing and evaluation of the comparative effects of different organic soil amendments 
in the revegetation of surface-mine spoils; 

(5) Testing and evaluation of comparative effects of selected inorganic fertihzers in the 
revegetation of surface-mine spoils; 

(6) Development of mechanical-chemical-vegetatiVe techniques for rehabilitating steep, 
abandoned surface-mine spoils; 

(7) Evaluation of the effectiveness of semiarid farming techniques known to be effective on 
various kinds of mine spoils; 

(8) Testing and evaluation of various spoil segregations and configurations for enhancement 
of rehabihtation success; 

(9) Development of mechanical criteria for construction of mine dumps to prevent mass 
slumping and to reduce surface erosion; and 

(10) Plant materials development and improvement. 

a. Determination of the physiological tolerances of selected plant ecotypes to various 
soil-water potential stresses and atmospheric evaporative-demand stresses on surface-mined 
spoils; 

b. Determination of physiological tolerances of selected plant ecotypes to sahne-alkaline 
stresses on various kinds of surface-mined spoils; 



IV-13 



c. Testing and evaluating hormine-stimulated rooting characteristics of native shrubs on 
abandoned, over-steep mine spoils; and 

d. Application of tissue-culturing techniques to develop increased tolerances of selected 
plant ecotypes to saline-alkaline stresses on surface-mined spoils. 

(c) Impacts of coal development on surface resources — 

(1) Analytical method.— An "analytical methodology" for analyzing the impacts of 
projected forecasts of coal development on surface resources was developed. Components 
consisted of: (a) basic assumptions, (b) steps in analysis, (c) rules for analysis, and (d) 
quantified definition of development levels (tables 4-2 and 4-3). 



IV- 14 



Table 4-2-Lands impacted (in acreages)*-total NGP 
CDP I 





1980 


1985 


2000 


2020§ 


2035§ 


Mined land' 
Plant facilities^ 
Ancillary facilities** 


5,387 
2,694 


16,142 
2,694 


50,478 
4,935 

44,879 


130,438 

4,935 

44,879 


190,408 

4,935 

44,879 


Total 


8,081 


18,836 


100,292 


180,252 


240,222 



CDP II 





1980 


1985 


2000 


2020§ 


2035§ 


Mined land' 
Plant facilities^ 
Ancillary facilities** 


5,500 
2,993 


19,409 
11,706 


100,795 

26,227 
82,518 


364,255 

26,227 
82,518 


561,850 

26,227 
82,518 


Total 


8,493 


31,115 


209,540 


473,000 


670,595 







CDP II 










1980 


1985 


2000 


2020§ 


2035§ 


Mined land' 
Plant facilities^ 
Ancillary facilities** 


10,938 
9,200 


44,107 
26,040 


227,705 

59,330 

109,890 


842,685 

59,330 

109,890 


1,303,920 

59,330 

109,890 


Total 


20,138 


70,147 


396,925 


1,011,905 


1,473,140 



*Acreages occupied by urban growth not determined, acreages occupied by ancillary facilities 

analyzed only for CPD III, year 2000 and 2035 and assumes all facilities would remain 

operational through 2035. 

'Acreages mined up to dates indicated. 

^Acreages occupied with plants, yards, and other facilities directly associated with plants and 

mines. 

**Acreages occupied by railroads, higliways, haul roads, transmission lines, aqueducts, and 

reservoirs were calculated only for CDP III at year 2000. 

§ Acreages for 2020-2035 are based on mines operating at year 2000 level or development. 



lV-15 



Table 4-3.-Acres of projected habitat losses to coal development in the study area' 

CDP I 





Year 


Species 


1980 


1985 


2000t 


Deer, mule, and white-tail 


6,370 


17,061 


51,359 


Antelope 


5,478 


14,914 


44,227 


Other big game 


167 


257 


527 


Sage grouse 


3,602 


8,647 


23,896 


Sharp-tailed grouse 


5,538 


14,329 


42,898 


Hungarian partridge 


5,116 


13,287 


39,270 


Ring-necked pheasant 


3,811 


10,702 


31,883 


Turkey 


826 


1,976 


5,939 



CDP II 





Year 


Species 


1980 


1985 


2000t 


Deer, mule, and white-tail 


6,141 


24,346 


91,523 


Antelope 


5,259 


20,548 


73,662 


Other big game 


167 


257 


527 


Sage grouse 


3,802 


16,127 


50,111 


Sharp-tailed grouse 


5,309 


20,018 


75,813 


Hungarian partridge 


4,887 


18,974 


69,784 


Ring-necked pheasant 


3,381 


12,771 


52,833 


Turkey 


826 


1,976 


10,509 



CDP III 





Year 


Species 


1980 


1985 


2000t 


Deer, mule, and white-tail 


18,507 


67,732 


277,255 


Antelope 


15,007 


58,594 


210,842 


Other big game 


167 


257 


2,216 


Sage grouse 


6,825 


24,716 


142,669 


Sharp-tailed grouse 


17,675 


59,958 


213,970 


Hungarian partridge 


15,907 


54.836 


177,795 


Ring-necked pheasant 


13,016 


43,177 


122,638 


Turkey 


5,809 


17,103 


83,208 



*Includes only good and medium quality habitat lost, except other big game and turkey also 
include low quality habitat. 

'Acreages stripmined between 1972-1975 are considered restored and have been subtracted 
from year 2000 totals. 



IV-16 



It was recognized at the outset that only subjective analyses were possible. Nevertheless, by 
employing a uniform and systematic approach, using matrix forms on which "affected 
factors," and degree and magnitude of disturbance were recorded, reasonably accurate 
approximations of impacts could be determined. 

Sample areas selected for intensive analyses included: 

Campbell County, Wyoming 
Big Horn County, Montana 
Rosebud County, Montana 
Mercer County, North Dakota 
Oliver County, North Dakota 
Considering Mercer and Oliver Counties as a single area, the local areas represent four sample 
areas where intensive mining developments were projected. Collectively, these four sample 
areas represented 89 percent of coal production in CDP I for year 2000; 61 percent of the CDP 
II; and 61 percent of the CDP III. Thus, by far a majority of regional coal development is 
represented in the four sample areas. 

Certain basic assumptions were prerequisite to the analyses. These were developed with the 
provision that additional ones as needed for particular resource considerations could be 
developed. 

Some of the basic assumptions follow: 

1. All mined lands will, as a minimum, be returned to current vegetal cover and use as 
nearly as possible. 

2. Mined areas will have soil and overburden replaced in same sequence as present within 
1 year following mining. 

3. Existing laws, regulations, and requirements will remain constant and in effect during 
the projection period (year 2000). 

4. Plant sites, reservoirs, transmission corridors, roads, towns, etc. will remain in place 
during all time frames through the projection period. 

5. Coal seam depths vary according to the particular formations where mines were 
sited. 

6. Assume the following acreages to be relegated to uses indicated for the duration of the 
projection period, dating from the time frame of establishment or operation: 



IV-17 



Gasification plant site 1 ,000 acres 

Gasification plant reservoir 30 acres 

Power generation plant 100 acres 

Power generation reservoir 50 acres 

Mine facility acreages 

Capacity less than 5 million tons per year 149 acres 

Capacity, 5 to 10 million tons per year 150 acres 

Capacity more than 10 million tons per year 153 acres 

7. No additional acreage allowed for either cleaning plant or tailings pond, if required. 

8. An acre foot of coal (80 percent efficiency in recovery) yields 1,416 tons. 

9. Assume the following conditions for mined lands: 

Campbell County, Wyoming. Mining disturbance will affect only productive rangeland. 

Assume 4 acres per Animal Uhit Month grazing. No cropland and no forest will be 

affected. 

Big Horn County, Montana. Mining disturbance will affect land resources thusly: 

Rangeland, 80 percent; forest land, 10 percent; cropland, 10 percent, divided 

equally between wheat and alfalfa. 
Rosebud County, Montana. Mining disturbance will affect land resources thusly: 

Rangeland, 80 percent; forest land, 15 percent; and cropland, 5 percent. 
Mercer and Oliver Counties, North Dakota. Best estimate available for probable land 
resource disturbance is: 

Mercer County: 55 percent rangeland; 45 percent cropland. 

Oliver County: 70 percent rangeland; 30 percent cropland. 
Assume for purpose of analysis, combining both counties: 

60 percent rangeland; 40 percent cropland. Assume cropland affected thusly: 

one-half wheat, one-fourth oats, one-fourth alfalfa hay. 

12. Assume 17,000 acre feet of water requirement for a gasification plant and 15,000 
acre feet for a wet-tower cooling electric power generator. 

13. Assume 5 years as time requirement to return mined acreage to stable productive 
cropland. Assume 5 years to regenerate, by planting, forest land. Assume 10 years to return 
rangeland to stable and productive grazing condition. For such uses as wildlife habitat, 
assume a minimum of 25 years. It should be noted that these estimates are only an educated 

IV-18 



guess, and that no field studies that would substantiate these guesses have been conducted in 
the NGP. 

(2) Summary of surface area to be disturbed. -As previously discussed, there are several 
activities associated with coal development that remove land from use for agricultural, wildlife, 
and recreation purposes. These include the mine pit, haul roads, storage and loading facilities, 
plant facilities, and storage reservoirs. In the operation of a mine, only portions of the area 
actually being mined can be returned to other productive uses during the life of the mine. The 
acreages committed to mining activities in the four sample areas are shown in tables 4-4, 4-5, 
4-6, and 4-7. The cumulative acreage of land that has been mined and that land occupied by 
related facilities are shown for the periods 1980, 1985, and 2000 as gross acreage. The net 
acreage is the number of acres that have been committed to mines and related facility uses 
minus the land that would be rehabilitated to grazing or cropland levels of productivity. 
Acreages committed to such uses as railroads, highways, haul roads, transmission lines, 
aqueducts, reservoirs, and urban development are not shown. These uses may equal or exceed 
the acreage shown in tables 4-4, 4-5, 4-6, and 4-7. The acreage committed to coal development 
activities including railroads, highways, transmission lines, aqueducts, and reservoirs for the 
total Northern Great Plains region is shown in table 4-2. 

(3) Assessment of impacts. — 

5'o/75.— The unique set of biotic, chemical, and physical properties constituting a given 
soil-plant system will be destroyed by surface mining. Soil structure will be altered; some 
soil micro-organisms will be lost; chemical properties will be changed; and water balances 
will be altered. The potential for erosion by wind and water will be increased to some 
unknown degree. 

Those soils overlying lands not mined but used to support other associated facihties will 
be altered to some unknown degree. Assuming erosion is controlled and these soils are not 
contaminated with foreign materials they should be easier to revegetate than mined land. 

The fate of trace elements and other substances emitted from coal conversion plants has 
not been adequately studied and hence no estimate of their impact on soils and on the 
micro and macro organisms associated with them can be made. 

Basic to all regional planning efforts is an understanding and inventory of the basic 
resources of the region, certainly one of the primary needs is for detailed soil surveys that 



IV- 19 



Table 4-4— Campbell County land area distrubed by mining and 
coal conversion facilities 



CDP 1 



Acreage 


1980 


1985 


2000 


Mines 
Facilities 


448 
599 


2,032 
599 


8,126 
1,047 


Gross 
Rehabilitated 


1,047 


2,631 

50 


9,173 

4,404 


Net 


1,047 


2,581 


4,769 


CDP II 


Acreage 


1980 


1985 


2000 


Mines 
Facilities 


509 
749 


2,543 

2,220 


12,670 

2,528 


Gross 
Rehabilitated 


1,258 


4,772 
65 


15,198 

5,984 


Net 


1,258 


4,707 


9,214 


CDP III 


Acreage 


1980 


1985 


2000 


Mines 
Facilities 


509 
749 


3,511 
6,069 


27,665 
9,650 


Gross 
Rehabilitated 


1,258 


9,570 

90 


37,315 

14,000 


Net 


1,258 


9,480 


23,315 



IV-20 



Table 4-5.— Bighorn County land area distrubed by mining and 
coal conversion facilities 



CDP I 



Acreage 


1980 


1985 


2000 


Mines 
Facilities 


325 
300 


1,269 
300 


4,931 
1,050 


Gross 
Rehabilitated 


625 


1,569 

37 


5,981 

2,525 


Net 


625 


1,532 


3,456 


CDP II 


Acreage 


1980 


1985 


2000 


Mines 
Facilities 


375 
450 


1,712 
2,812 


9,212 

4,587 


Gross 
Rehabilitated 


825 


4,524 

44 


13,799 

4,256 


Net 


825 


4,480 


9,543 


CDP III 


Acreage 


1980 


1985 


2000 


Mines 
Facilities 


469 
1,631 


2,375 
4,144 


14,875 
12,719 


Gross 
Rehabilitated 


2,100 


6,519 

56 


27,594 

6,587 


Net 


2,100 


6,463 


21,007 



IV-21 



Table 4-6. -Rosebud County land area disturbed by mining and 
coal conversion facilities 



CDP I 



Acreage 


1980 


1985 


2000 


Mines 
Facilities 


2,256 
300 


4,894 
300 


14,912 
600 


Gross 
Rehabilitated 


2,556 


5,194 

156 


15,512 

8,387 


Net 


2,556 


5,038 


7,125 


CDP II 


Acreage 


1980 


1985 


2000 


Mines 
Facilities 


2,256 
300 


5,425 
1,631 


23,437 
3,262 


Gross 
Rehabilitated 


2,556 


7,056 

175 


26,699 

1 1 ,600 


Net 


2,556 


6,881 


15,099 


CDP III 


Acreage 


1980 


1985 


2000 


Mines 
Facilities 


2,537 
1,481 


7,862 
5,325 


45,169 
6,069 


Gross 
Rehabilitated 


4,018 


13,187 

250 


51,238 
20,550 


Net 


4,018 


12,937 


30,678 



IV-22 



Table 4-1 .—Oliver and Mercer Counties land area disturbed by mining and 

coal conversion facilities 



CDP I 



Acreage 


1980 


1985 


2000 


Mines 
Facilities 


3,283 
600 


6,000 
600 


16,600 
900 


Gross 
Rehabilitated 


3,883 


6,600 

1,250 


17,500 

10,783 


Net 


3,883 


5,350 


6,717 


CDP 11 


Acreage 


1980 


1985 


2000 


Mines 
Facilities 


3,283 
600 


6,708 

1,775 


28,333 
3,558 


Gross - 
Rehabilitated 


3,883 


8,484 

1,333 


31,891 

15,250 


Net 


3,883 


7,150 


16,651 


CDP 111 


Acreage 


1980 


1985 


2000 


Mines 
Facilities 


2,537 
1,481 


7,862 

5,325 


45,169 
6,069 


Gross 
Rehabilitated 


4,018 


13,187 

250 


51,238 

20,550 


Net 


4,018 


12,937 


30,688 



lV-23 



provide basic information concerning agricultural potential of soils, wildlife habitat 
potentials, and rehabilitational potential. 

Vegetation. —Surf ace mining and associated plant and facilitating structures will destroy 
existing vegetation. Its restoration will require extensive rehabilitation measures. The 
resource needs related to rehabilitation are discussed in Rehabilitation Potential (section 
4-2(b)) of the NGP Surface Mineable Lands. Additional needs are surveys of specie 
composition density and productivity at a level of detail that would describe those 
conditions that must be obtained by rehabilitation measures. Assuming rehabilitation 
technology is available, sources for seeds and plants suitable for rehabilitation needs must be 
developed. 

As with soils, the impact of coal conversion emissions particularly trace elements and SO2 
are poorly understood and further study is needed. 

Agriculture. -A more detailed examination of the impact of coal development on the 
agricultural economy is found in section 5-5. 

Wildlife.— The adverse impacts of coal development on the wildlife resources of the NGP 
will be associated with the direct loss of habitat (table 4-2) resulting from mining and 
associated activities and urban development and the disturbances caused by human 
activities. Intolerant species may abandon an area that can provide their physical needs 
(food, water, and shelter) when human activity interferes with certain behavioral activities 
necessary to their survival. Assessment of the impact of coal development activities on 
wildlife resources is compounded by the fact that animals occupy different habitat at 
different times of the year and in some cases the day. For this reason the destruction of land 
in one area may obviate the use of land in another even though it has not been disturbed. 
The classical example is the general shortage of winter deer range. 

Throughout the west there is an abundance of land that provides suitable habitat for deer 
during the spring, summer, and fall periods. These ranges are not utilized because the winter 
range is not sufficient to support the same population levels that could be supported by the 
other ranges. The winter range is therefor the factor that limits the deer population. 

If coal development occurs in habitat types that are presently the factor limiting the 
growth of a particular wildlife population, it will reduce that population in that area as well 
as all other areas occupied by that population. Unfortunately, an assessment of such impacts 



IV-24 



is not possible because of a general lack of knowledge about the wildlife of the NGP and 
their requirements. 

The evaluation of the impact of coal development presented here is primarily the result of 
subjective analysis by persons who are famiHar with NGP wildlife populations and their 
trends. An objective assessment will require detailed studies of population dynamics, 
behavioral characteristics, and ecological relationships of NGP wildlife. 

Within these hmitations the following conclusions warrant considerations. 

CDP I 

In the CDP I, by 1980 more than 8,000 acres of land will be occupied or physically 
disturbed by coal development in the NGPRP study area. The human population will 
increase by about 14 percent over that of 1970. Except for some species, which are 
threatened or endangered and for some local wildlife populations, effects on fish and 
wildlife habitat in the region will be minor. 

In the CDP I, by 1985 some 17,000 acres will be lost to development and the population 
will increase by 31,000, or 8 percent over the 1970 level. The increased population may 
cause an additional decrease in the habitat of the peregrine falcon, since the spring and fall 
migration habitat of this bird encompasses most of the northern prairie, and more people 
will occupy that habitat. There will be slight but important decreases in ring-necked 
pheasant and wild turkey habitat. 

Hunting pressure for elk will increase both in the study area and to the west. Applications 
for moose, bighorn sheep, and mountain goat hunting permits will increase slightly. Hunting 
pressure on sage grouse and on ring-necked pheasant in the western part of the study area 
will increase so that the average hunter's success will noticeably decrease. 

By the year 2000, development will have occupied more than 100,000 acres and 74,000 
more people will reside in the area than did in 1970. It is probable that the peregrine falcon 
will no longer nest in Montana or Wyoming by that time, and spring and fall migrants will be 
reduced to a very rare visitor. 

The endangered black-footed ferret and the western burrowing owl (status undetermined) 
are dependent on the black-tailed prairie dog. Coal development may cause significant 
decreases in the number of prairie dog towns, adversely affecting the ferret and owl. 



IV-25 



Inexpliciably, some people shoot hawks. The ferruginous hawk, prairie pigeon hawk, and 
prairie falcon are status-undetermined species resident in the study area. The projected 
human population increase by the year 2000 causes serious concern for these birds of prey. 

Losses of game animal habitats will affect the wild turkey the most but sage grouse and 
ring-necked pheasants will lose significant habitat areas. Although only 5,900 acres of 
turkey habitat will be destroyed, the losses will occur in some of the better habitat areas. 
The sage grouse has experienced significant habitat losses recently because of large-scale 
sagebrush eradication programs. Under this forecast, an additional 24,000 acres of good and 
medium quality habitat will be lost. In view of trends, this is significant. In the region, 
better sagebrush habitat exists north and southwest of most development. 

Also, in view of present trends, the loss of an additional 5,800 acres of good and medium 
quality ring-necked pheasant habitat assumes significance, particularly to the west of the 
Dakotas. 

Regionally, most hunting will be moderately changed by the year 2000. There will be an 
estimated 13,000 more deer hunters, 3,300 more antelope hunters, and 7,600 more hunters 
seeking other big-game species. 

In both North Dakota and South Dakota nonresidents are allowed to hunt big game; 
however, the percentage of nonresident hunters is very low. Increases in the number of 
resident hunters in those states will result in decreasing opportunities to hunt deer and 
antelope. 

Locally, popular fishing sites will become overcrowded, but regionally fishing demand 
will not exceed the supply. 

CDP II 

By 1980, the CDP II development will have covered or disturbed 8,500 acres. The 
population of the area will increase by 61,000 over that of 1970. 

Regionally, little besides raptorial habitat will be significantly affected. Deer hunting in 
North Dakota will have noticeably changed— mainly by increased access difficulty and 
decreased hunting. Hunting for other big game will have changed slightly in that elk hunting 
conditions will be more restricted and opportunities to hunt other species will be reduced. 
Of upland game hunting, only sage grouse and ring-necked pheasant hunting will be 
regionally affected— by a few less birds, shorter seasons, and for pheasants, more restricted 
access to hunting areas. 

IV-26 



By 1985, more than 31,000 acres of land will have been disturbed, destroyed, or 
occupied. The area's population will increase by 135,000— a 36 percent increase over 1970. 
The population increase is twice that of CDP I in the year 2000, but the land disturbance 
related to coal development is only one-third that projected for the year 2000, CDP I. It is 
believed human population increases will have greater impacts on fish and wildlife than will 
land disturbance attributable directly to coal development. For this year, then, 
approximately twice the impacts on fish and wildlife resources will occur as projected for 
the CDP I, year 2000. One mitigating factor is that the impacts would have 15 fewer years 
to be realized; for some species and hunting situations, such as sage grouse hunting, that 
may be significant. 

By the year 2000, CDP II, the area's human population will have swelled by 100 percent 
or 376,000 more people than in 1970. More than 209,000 acres will be committed to coal 
development. Adverse impacts on wildlife resources and on hunting will be significant. 

Because of the magnitude of change, the extirpation of the peregrine falcon in the study 
area, both as a summer nester and as a spring and fall migrant is predicted along with 
significant reductions in population levels of all raptors. 

By year 2000, enough better habitat of white-tailed and muledeer, sage grouse, 
ring-necked pheasant, and wild turkey will have been destroyed to cause serious concern 
among game managers and to be readily noticed by the outdoor public. Hunting for all 
big-game species and some upland game (sage and sharp-tailed grouse, pheasant, turkey) will 
be seriously degraded. 

Significant decreases in success ratios for deer, elk, and antelope will adversely affect the 
nonresident guiding and outfitting industry. Nonresidents traveling long distances would 
rather drive a httle farther to areas where chances for harvesting game were better. 

CDP III 

Regional impacts in 1980 under the CDP III are generally comparable to impacts in 1985 
under the CDP II. 



IV-27 



By the year 2000 in the CDP III, the area's population will increase by 497,000 or 132 
percent. Coal development will have destroyed almost 400,000 acres of wildHfe habitat. The 
following impacts are projected: 

1. Some 277,000 acres of good and medium quality deer habitat will be lost— almost 
69,000 more deer hunters will compete with the current number of hunters for less deer. 

2. Hunting for elk in Montana and Wyoming will be significantly degraded by loss of 
habitat and the addition of over 29,000 more resident elk hunters. 

3. Sage grouse hunting has had a long-term trend in the region toward longer seasons 
and more liberal conditions. This trend will be abruptly reversed and by the year 2000 
sage grouse hunting will be far more restricted. 

4. Over 83,000 acres of turkey habitat will be destroyed. Turkey populations will be 
significantly reduced. However, a harvestable surplus will be available annually and turkey 
hunting will continue, although under far more restricted circumstances than at present. 

5. Raptors will loose 295,000 acres of hunting grounds and will be subject to 
intentional and unintentional persecution by 497,000 more people. Impacts on resident 
and wintering raptors will be significant; impacts on migrating raptors are speculative. 

6. Local populations of passerine birds will be eliminated. Effects on many species will 
be long term because it is unrealistic to project restoration of disturbed lands to natural 
levels of plant variety within a short time frame. Currently, the relationships of the 
hundreds of passerine species to the several ecosystems of the area is little understood by 
game biologists and land managers. The relationships probably serve a more important 
role in the prairie ecosystems than is widely appreciated. 

7. Local populations of some endangered or threatened species will likely be 
extirpated. Any loss of individuals of these species would be disastrous. Candidates for 
losses include: American peregrine falcon, black-footed ferret, prairie falcon, prairie 
pigeon hawk, western burrowing owl, mountain plover, northern long-billed curlew, and 
ferruginous hawk. 

Wilderness-wild lands— Actual mining operations will have little effect on the inventoried 
wilderness-wild land resource. All impacts on existing areas of the wilderness system will be 
caused indirectly by increased use or possible water modifications or developments. 
Increased use will result in some loss of opportunities for solitude within the wildernesses. 
Visitors seeking solitude may have to penetrate further or pick seasons when use is light. 

IV-28 



No proposed units to the National Wilderness Preservation System are directly affected 
by the projected mining operations. Any impacts will likely result from increased use or 
projects affecting waterflows from these areas. 

Scenery .—Analysis of impacts on scenery is limited to the four sample areas. It was 
determined that an impact analysis on a regional basis was impracticable. There is also a major 
problem of attempting to compare qualities among entirely different types of scenery, that is, 
the scattered pines on hills near Colstrip, Montana, versus the Knife River Valley in North 
Dakota. 

Development of power and gasification plants and anticipated smoke plumes would have 
the greatest impact on scenic views. In Big Horn County, Montana, except for possible plume 
impact, the degree of impact is considered low. 



IV-29 



2. Water Resources 

4-3. Introduction. -The conversion of coal to electricity or synthetic gas in the Northern 
Great Plains is intricately linked to water supplies. Without sufficient water at a reasonable price, 
coal conversion may be restrained. High water costs may affect the rate of coal development and 
water diversions for coal development may have to compete with existing uses and their future 
growth. In addition to water depletions, upstream users will discharge effluents that may affect 
the quality of water for downstream users. 

These are but a few of the interrelationships between energy development and water. Listed 
below are the principal water issues concerning the Northern Great Plains. To resolve these issues 
is impossible. However, to highlight and discuss them is the principal purpose of this section. 

—What are the existing water resources in the NGP and, how are they being used? 

—What will the future demands on these resources be? 

-How much water is available for energy development? 

—What will water cost? 

—What will be the impacts of increased water used for energy resource development? 

4-4. Historic Background.— 'Water has played an important role in the development of the 
semiarid Northern Great Plains. Early exploration and settlements followed the river networks 
which comprise the Missouri River Basin. With the invention of the windmill, a greater dispersion 
of the settlements was allowed by insuring the farmer a convenient water supply for his 
household and a herd of livestock. 

Just as the land resources of the Northern Great Plains are utilized to near capacity for grazing 
and farming activities, so also are the available water resources. Overriding other factors in the 
pattern of water supply and use is the very wide fluctuation in flows from season to season and 
from wet year to dry. Many significant rivers dry up for long stretches during drought years. Even 
in normal years, a higli percentage of the total flow occurs during late spring. On the downstream 
eastern edge of the Northern Great Plains and at a few scattered sites within the region, water is 
impounded to insure more reliable supplies. However, the Yellowstone River and all of its 
tributaries, with the exception of the Bigliorn, are largely unregulated and undisturbed by 
impoundments. 



IV-30 



As water is a commodity of considerable value, a system of laws has evolved to determine who 
has the right to water. Water laws based on both the appropriation rights doctrine and the 
riparian rights doctrine have been adopted by the Northern Great Plains states. 

The common-law doctrine of riparian rights is based primarily on the ownership of land and 
uses of water thereon contiguous to the stream. Under the Riparian Rights Doctrine, the owner 
of land contiguous to a natural stream or natural lake may use the waters for such purposes and 
in such quantities as he chooses, as long as he does not appreciably diminish the flow or impair 
the quahty of water for downstream users. Such rights are not expressed in specific quantities of 
water unless they have been apportioned by the court. There is no priority of right althougli 
domestic use and the watering of domestic livestock are generally considered preferrential uses. 
Riparian rights are not usually transferable to land not contiguous to the stream or lake from 
which the water is being drawn. 

Under the appropriation rights doctrine the beneficial use (as defined by each state) of water is 
the basis, the measure, and the limit of the water right. The first beneficial appropriation is prior in 
right. Appropriations are for a definite rate of diversion or storage and often the quantity is 
specified. The appropriation right is obtained and sustained only by actual and continuous 
beneficial use. Failure to make beneficial use of an appropriation may result in its loss. Appropriated 
water may be used either on land contiguous to or a distance from the water source. 

4-5. Surface Waterftow Conditions. -A number of rivers and basins in the Northern Great 
Plains region were and are being studied to determine rehable flow condition information: 

(a) Yellowstone River Basin, Montana, and Wyoming. -The highest stream flow rates in the 
Yellowstone River Basin (fig. 4-1) occur in May and June and are produced by snowmelt and 
rainfaU in the mountainous areas. The average flows that occur during this period are 5 to 10 
times the average flows that occur in fall and winter months. Critically low flows, sometimes 
approaching no flows in some tributaries and streams, occasionally occur in the fall period 
causing serious water use problems for irrigators and adversely affecting fish and wildlife 
resources. Significantly less water is available during these drought conditions, than shown in 
figure 4-1. For example, the lowest recorded average June flo^w in the Tongue River at Miles City, 
Montana, is 5,997 acre-feet as compared with the historic average of 115,644 acre-feet. The 
Bighorn River is the only major stream in the Yellowstone Basin that is regulated. This is 
accompUshed by controlled storage in Yellowtail and Boysen Reservoirs which are primarily 



IV-31 



operated for power generation, flood control, and irrigation purposes. Monthly average flow 
releases are shown in figure 4-2. 

(b) Western Dakota Tributaries of the Upper Missouri River.— Unlike the Yellowstone Basin, 
the western Dakota tributaries of the upper Missouri River are relatively short and do not drain 
mountainous areas. Earlier snowmelt (than in the high elevations of the Yellowstone watershed) 
in this plains region causes relatively high flows as early as March and April in the Little Missouri, 
Knife, Heart, and Cannonball Rivers (fig. 4-3). Overall, the flows in these rivers are substantially 
less than in the Yellowstone Basin and drought periods, intensified by the small watershed area, 
seriously constrain water use and productivity of aquatic resources. 

(c) Main Stem Missouri River.— The Missouri River flows are not subject to much seasonal 
variation as they are regulated at Fort Peck, Garrison, and Oahe Dams for purposes such as 
electric power generation, flood control, and downstream navigation. Monthly average flows 
released from Garrison are shown in figure 4-4. 

The shortage of water during years with low amounts of precipitation promoted the 
development of the large water impoundments for water storage in the Northern Great Plains 
referred to above. (Boysen, Yellowtail, Fort Peck, Garrison (Lake Sakakawea), and Oahe.) The 
purpose of these reservoirs is to help assure necessary water supphes to users along the Bighorn, 
Yellowstone, and Missouri Rivers. Demand for water can, however, still exceed streamflow and 
storage releases in selected tributaries, and in many years they become completely dewatered for 
some period (table 4-8). 

4-6. Current Trends and i/ses.— Irrigation consumes a major portion of water in the Northern 
Great Plains region. In the Yellowstone River Basin of Montana and Wyoming it is estimated that 
about 1.25 million acres of farmland are under irrigation. A total of approximately 2.26 million 
acres are irrigated above Lake Sakakawea in the Missouri and Yellowstone River Basins. The 
planned Garrison and Oalie irrigation projects, if completed, would irrigate approximately 1-1/2 
million acres in the Dakotas and utilized about 3.5 million acre-feet of water from Lakes 
Sakakawea and Oahe. 

Loss of water through evaporation from large reservoirs exceeds all other consumptive uses 
combined (fig. 4-5). Practices such as contouring, terracing and erosion control, and small 
impoundments for fisheries, recreation, stock watering, and small irrigation projects are also 
shown to be significant water consumers. 



lV-32 



















































































TONGUE RIVER 
1 1 1 














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JAN. FEB. MAR APR. MAY JUNE JULY AUG. SEP. OCT. NOV. DEC 



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150 
140 
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110 
100 
90 
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70 
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1 1 1 1 












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JAN FEB MAR. APR. MAY JUNE JULY AUG. SEP OCT NOV DEC 



Figure 4-1. Historic Yellowstone River Basin flows. 



(SUBSEQUENT TO YELLOWTAIL RESERVOIR STABILIZATION) 


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9 nnn 


























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JAN. FEB. MAR. APR. MAY JUNE JULY AUG. SEP. OCT. NOV. DEC. 



Figure 4-2. Releases from YellowtaH Dam. 



































































































NE 


\R V 


ATF 


LITTLE MISSOURI RIVER 

1 1 1 1 1 
ORD CITY, NORTH DAKOT/ 

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Table 4-8.— Days for which flows of less than 0. J ft^ /s were recorded 
in the Yellowstone and Western Dakota tributaries 





Period of 


Less than 0.1 ft^s 


flow recorded 


River 


Average number of days 


Annual 


location 


record 


of occurrence in a year 


percent occurrence 


Tongue River at 








Miles City, Montana 


1961-1970 


*0.0 





Powder River near 








Locate, Montana 


1939-1971 


1.6 


0.4 


Little Missouri River 








near Watford City, 








North Dakota 


1935-1971 


34.7 


9 


Knife River at Hazen, 








North Dakota 


1930-1971 


2.7 


0.7 


Heart River near 








Mandan, North Dakota 


1929-1971 


16.4 


4 


Cannonball River at 








Breien, North Dakota 


1935-1971 


22.3 


6 



*Zero flow recorded for July 9-19, Aug. 13, 14, and Sept. 28, 1940. 

In addition to consumptive water use, there are many nonconsumptive uses such as 
hydroelectric power generation, navigation, fish and wildlife, recreation, and aesthetics. Some of 
these, such as hydropower and navigation, do not consume water. However, they sometimes 
require impoundment which causes a water loss through evaporation. All of these uses require 
that a stream cannot be completely depleted of water and as such, require allocation of the 
available water similar to that required by the previously discussed consumptive uses. 

Approximately 87 percent, or 2,048 megawatts, of the hydropower capacity which is in the 
study area, or affected by it, is installed at the six main stem dams on the Missouri River: Fort 
Peck in Montana, Garrison in North Dakota, and Oalie, Big Bend, Fort Randall, and Gavins Point 
in South Dakota. Total hydropower capacity in the Yellowstone Basin is 296 megawatts, 250 
megawatts of which are at Yellowtail Dam on the Bighorn River. 

There is no major commercial navigation in the Missouri Basin above Sioux City, Iowa; 
however, downstream barge-tow transportation of farm products depends upon water stored 
behind the Missouri main stem dams. Indications are that under present conditions a rate of flow 
of 25,000 to 31,000 cubic feet per second (18 to 23 milhon acre-feet per year) would be 
adequate to support a 9-foot navigation channel downstream of Sioux City with nominal 
dredging. 



IV-33 



The thrust of new development is currently shifting water use from agriculture to industry. (It 
is possible that this situation will change dramatically or be compounded by the need for 
increased food production.) Indications of this shift are the Federal Industrial Water Option 
Contracts and appUcations for stored water in the NGP. 

Since 1967, option contracts to purchase Federally owned storage water have been made or 
are pending with many companies. An option contract is bought for a relatively nominal charge 
by the purchaser and will reserve, for a certain period', water in storage for future use. Additional 
appUcations for contracts to purchase Federally owned storage water have been received but are 
not yet in effect. Table 4-9 summarized this information for both existing and nonexistent 
(Moorhead Reservoir, New Tongue River Reservoir, and Yellowstone River) storage sites. It 
should be noted that these data indicate potential future water use involving a degree of 
uncertainty for the companies and, as such, is speculation similar to that of buying land underlaid 
with coal. 

The sliift away from the use of water for new irrigation is primarily the result of the new 
standards for Federally funded water projects for which discount rates are now 5-7/8 percent. 
Under the new standards and at the current discount rate, essentially no new Federally funded 
irrigation projects are economically justifiable. There will undoubtedly be some private and 
state-assisted irrigation in the future, and projects presently under construction may be expected 
to continue. 

4-7. Water Demand.— (a) Water for Coal Conversion.— To conduct water-supply studies for 
coal development and assess the impacts of such water development, assumptions pertaining to 
the quantity of water used at powerplants and gasification plants were necessary. The original 
assumptions were: 

( 1 ) Powerplants require 1 9,000 acre-feet of water per 1 ,000 MW generated, and 

(2) Gasification plants producing 250 milUon standard cubic feet per day require 30,000 
AF^ 

These assumptions were made early in 1973. Since then, new information has been developed 
indicating these figures to be too higli. The issue is discussed below and the revised estimates of 
water needs are presented; however, all of the water supply studies and impact assessments were 
based on the original assumptions. 



'Goldman, E. and Kelleher, P., Water Reuse in Fossil Fueled Power Stations. In: Complete Water Reuse, Cecil, L. K. (ed.). 
New York, N.Y., American Institute of Chemical Engineers, April 1973, p. 240-249. 

IV-34 



Table 4-9.— Federal industrial water option contracts and 
applications as of December 1973 





Water options contracts 






in effect 


Water option contract 


Water source* 


or pending 


applications 




ac-ft per year 


ac-ft per year 


Boysen Reservoir, 






Wind River, Wyoming 


85,000 


59,000 


Yellowtail Reservoir 






Bighorn River, Montana 


623,000 


630,000 


Tongue River Reservoir 






Tongue River, Montana 


4,175 





Moorhead Reservoir (potential) 






Powder River, Montana 





220,000 


Fort Peck Reservoir** 






Missouri River, Montana 





310,000 


Lake Sakakawea** 






Missouri River, North Dakota 





124,000 


Lake Tschida 






Heart River, North Dakota 





18,000 


Yellowstone River, Montana 





630,000 


Totals in Upper Missouri Basin 


712,175 


1,991,000 



*Water Work Group Report. 
**Main stem storage. 

A typical water-cooled 1,000 MW coal-fired powerplant in the NGP will utilize water for a 
variety of processes. The majority of the water will be used for evaporative coohng. This process 
will utilize around 10,000 to 12,000 acre-feet per year. Anywhere from 700-3,000 acre-feet will 
be consumed for ash handling depending on the methods used. If a wet SO2 scrubber is used, it 
will consume about 3,000 acre-feet per year. There are other incidental water needs but they are 
minor compared to the above uses. The total water requirement for a 1 ,000-megawatt plant 
ranges between 12,000 and 15,000 acre-feet per year. The lower figure represents a plant that 
does not utilize a wet SO2 scrubber. 

Dry cooling systems, which use air instead of water, may significantly reduce the need for 
water. It is difficult to estimate the water needs for a 1,000 MW plant because only one dry 
coohng plant has been built in the NGP and it is less than 30 MW (construction of a 330 MW 
dry-cooled plant is being started at the same location). However, water usage estimates range 
from 500 to 5,000 acre-feet per year for a 1,000 MW plant. Though dry cooling conserves water, 
its capital and operating costs are significantly higher tlian for wet coohng. Only where the cost 
of water is substantial is dry cooling economically preferable to wet cooling. One recent study 



IV-35 



indicates that when dehvered water costs are more than about $200/AF-acre-feet; dry cooling 
then becomes more economical than wet cooling. For CDP I, the delivered cost of water is less 
than $200 per acre-foot for all of the six powerplant sites. In CDP II, those powerplants sited 
more than 100 miles from the point of diversion may find that dry cooling is more economical. 
In CDP III, water costs are slightly lower because of economies of scale; thus, dry cooHng 
becomes economic somewhere beyond around 150 miles from the diversion point. If ground 
water could be combined with a wet-cooling process, this would probably be more economical 
than dry cooling. 

Water is also necessary for the production of synthetic natural gas from coal. Precise 
quantification of water demand is difficult, as there are no coal gasification plants operating in 
the United States and the final quantification of the water demand revolves around a technology 
yet to be developed. Nevertheless, estimates of water needs have been made, for the Lurgi 
process, by process developers and plant designers. 

The two most critical uses for water in coal gasification are as a source of hydrogen in the 
gasification reaction and for process steam. One study has shown that as a hydrogen source, the 
minimum water requirement was about 4,000 acre-feet per year for a 250-million scf/day 
(standard-cubic-feet-per-day) plant. ^ Additional studies have stated the lower hmit to be 2,300 
acre-feet per year.'* There are significant cooling requirements associated with coal gasification as 
well as numerous miscellaneous water uses similar to a powerplant. Estimates of total water 
required for a 250-million scf/day plant have ranged as high as 30,000 acre-feet per year^ when 
total evaporative cooling is used. 

Utilizing the design plans of those few gasification plants proposed to be built in the United 
States for estimating plant water requirement, the range can be narrowed from 8,000 to 12,000 
acre-feet per year. This assumes both wet- and dry-cooling systems for the various plant systems. 
A better understanding of the Lurgi process on western coals, coupled with moderate advances in 
technology, may further lower this requirement to a range of 6,000-10,000 acre-feet per year. 
Currently, a "best estimate" for the NGP would appear to be 9,500 acre-feet per year for a 
250-mLllion scf/day plant. If significant additional water is used, discharges would result. 



Office of Coal Research, Annual Report, 1973, pp. 31-34. 

Washburn, Charles, "Environmental Impact of Large Scale Coal Gasification Development" a report prepared for the EPA, 
Ecological Studies and Technology Assessment Branch, August 1972. 

^ Final Report of the Supply-Technical Advisory Task Force— Synthetic Gas— Coal; prepared for the National Gas Survey of 
the Federal Power Commission; April 1973. 



IV-36 



Table 4-10 shows a comparison of regional water requirements for various use alternatives and 
the levels of coal development assumed in each CDP. 



Table 4-10.— Comparison of potential water use estimates 
for each CDP during years J 980, 1985, and 2000 



Year 1980 



Megawatts 
MW 



Synthetic 

natural gas 

(SNG) plants 



High water use 
estimate,* acre- 
feet per year 



Conservation 

water use 
estimate, t acre- 
feet per year 



Low water use 
estimate,** acre- 
feet per year 



CDP I 
CDP II 
CDP III 





210,000 







66,500 







42,000 



Year 1985 



CDP I 
CDP II 
CDP III 





7 
20 





210,000 
600,000 





66,500 
190,000 





42,000 

120,000 



Year 2000 



CDP I 
CDP II 
CDP III 



6,500 
12,800 
4 2,800 




16 
41 



123,500 

723,200 

1,473,200 



78,000 
305,600 
543,000 



32,500 
160,000 
310,000 



*Assumes 30,000 af/y for a gasification plant and 19,000 af/y for 1 ,000 MW of electricity, 
t Assumes 9,500 af/y for a gasification plant and 12,000 af/y for 1,000 MW of electricity. 
**Assumes 6,000 af/y for a gasification plant and 5,000 af/y (dry cooling) for 1,000 MW of 
electricity. 

(b) Water for Municipal and Domestic L'^se.— Utilizing NGPRP estimates for increases in 
population resulting from development of new coal mines, powerplants, gasification plants, and 
associated growth, an estimate of municipal water needs can be developed as shown in table 4-11. 
The estimated water needs are based on an assumed municipal water requirement of 
125-gallons-per-person per day. The range in municipal water requirements is generally between 
100 (Gillette, Wyoming) and 200 (Billings, Montana; Bismark, North Dakota) gallons-per-person 
per day. It should be noted that as population increases per capita water consumption increases. 

(c) Water for Revegetation of Mined Lands .—RQVQgQtation of strip mined lands may also 
require water for irrigation particularly during drought conditions. Although revegetation may be 



IV-37 



Table 4-1 \.— Estimated additional municipal water needs for the region 





Projected population 
increase 


Million gallons 
per day 


Acre-feet 
per year 


CDP I 
CDP II 
CDP III 


74,000 
237,000 
497,000 


9.25 
29.63 
62.13 


10,300 
33,100 
69,300 



accomplished without irrigation when rainfall amounts are adequate, water will have to be 
allocated for revegetation for possible drought occurence. Assuming that the minimum annual 
precipitation requirement is 12 inches (the average rainfall in some areas) and that 2 consecutive 
years of normal precipitation is required for revegetation of grasses, and that drought conditions 
may provide only 4 inches of precipitation, an estimate of the supplemental revegetation water 
requirement can be made. By year 2000, the high level of coal development (CDP III) will require 
an estimated revegetation of 30,750 acres every year. Assuming that at least 2 consecutive years 
are needed for establishment of grasses, in a drought year, 61,500 acres would require irrigation. 
Therefore, 8 inches (12 in. -4 in.) of irrigation over this land area would require annually 41,200 
acre-feet. Table 4-12 summarizes this water requirement for the other coal development profiles. 
A mine disturbing approximately 700 acres per year (assume a thin coal seam) would need 950 
acre-feet while a single mine disturbing 100 acres per year (assume a thick coal seam) would need 
only 135 acre-feet per year. Although this amount of water probably would not be used every 
year (less water would be needed when rainfall exceeded 4 inches), it is obvious that a system to 
supply water to mine sites for use in revegetation during drouglit conditions will be needed along 
with the appropriate water riglits. 

As this use of water will correspond to drought conditions when water may be in short supply 
for competing uses, storage of water at or available to the mine site for revegetation purposes 
may be necessary. If the "revegetation" water riglits are "junior," then revegetation efforts could 
severely suffer. 

(d) Water for Slurry Pipeline Export .—S\\xxvy pipeline export of coal also represents a 
potential water use. Although there is some uncertainty about the water requirements for this 
use, data from the slurry pipehne currently being planned for the Gillette area, indicates that the 
annual water requirement will be 600 to 800 acre-feet per million tons of coal transported. Using 
this water requirement, table 4-13 shows the amounts of water required for slurry pipeline 
transport of half or all mined coal projected for export. 

lV-38 



I 



'Table 4-12.— Water requirement for revegetation, year 2000 









Supplemental 




Acres 


Area 


irrigation 




being mined 


undergoing 


requirement 




acres/year 


revegetation 


acre-feet/ 






acres/year 


year 


CDP I 


4,000 


8,000 


5,300 


CDP II 


13,200 


26,400 


17,700 


CDP III 


30,750 


61,500 


41,200 



Table 4-\3. — Water requirements for slurry 
pipeline export of coal, year 2000* 









Water need when 


Water need when 






all coal is 


one-half coal is 




Coal exported 


exported by 


exported by 




million tons 


slurry pipeline 


slurry pipeline, 






acre-feet/year 


acre-feet/year 


CDP I 


88 


61,600 


30,800 


CDP II 


110 


77,000 


38,500 


CDP III 


534 


373,800 


186,900 



*Calculations of water required based on 700 acre-feet per million tons of coal transported. 

(e) Total Potential Water Demand.— K perspective of the potential total water requirement for 
the region for the year 2000 can be gained by combining the various water demands discussed 
previously with those projected by the MRBC (Missouri River Basin Commission) for agriculture 
for the Missouri Basin above the confluence of the Missouri and Yellowstone, and Yellowstone 
Basin and the Western Dakota tributaries. Not included are the depletions which may result from 
development of the Garrison and Oahe projects. Initial phases of these two irrigation projects are 
estimated to require 871,000 acre-feet and 599,900 acre-feet, respectively. Ultimate phase 
requirements would equal 3,500,000 acre-feet. 

Assuming institutional requirements or water costs promote some conservation of water by 
coal conversion plants, then the conservation water use estimates given in table 4-10 give the 
most Ukely estimates of the power and gasification plants water requirements. By adding these 
industrial plant water needs to projected municipal, revegetation, and slurry pipeline water needs, 
an estimate of the total water requirements for coal development in the region can be determijied 
as shown in table 4-15. 



IV-39 



Table 4-\4.—MRBC* projected surface water demands for year 2000 




Water demand 


Upper Missouri Basin 
(above Lake Sakakawea) 


Yellowstone 
Basin 


Western Dakota 
tributaries 


Total 




All in thousands of acre-feet per year 






Cropland irrigation: 

Full service 
Supplemental 

Livestock 


512.2 
116.0 

24.2 


683.6 
102.5 

23.7 


455.0 


26.0 


1,650.8 
218.5 

73.9 


Evaporation: 

Large reservoir 
Small reservoir 
Ponds 


20 

17.7 

14.8 


21.7 
37.3 
35.2 


28.0 

143.0 

10.0 


69.7 

198.0 

60.0 


Total 


704.9 


904.0 


662.0 


2,270.9 



*MRBC Comp Fram Study, vol 6, Hydrologic Analysis and Projections Appendix, tables 23, 
24, and 25, pp. 130-131, Dec. 1971. 



Table 4-1 5. -Coal development related water depletions for 2000 
(estimates in acre-feet) 



Coal conversion (CDP III) 
Municipal (CDP III) 
Revegetation (CDP III) 
Slurry pipeline (CDP III)* 


543,000 
69,300 
41,200 

186,900 


Total 


800,400 



* Assumes 50 percent of exported coal shipped by slurry pipeline. 

4-8. Water Availability .-In exploring the methods of supplying water to the various levels of 
coal development activities theorized in each CDP, it was assumed that flows would not be 
depleted to a point that would threaten the aquatic and aestlietic values associated with NGP 
streams. In developing the hypothetical water supply system, this constraint was applied in all 
cases except for parts of the Bighorn and Yellowstone Rivers in CDP III. The flows needed to 
maintain these values are referred to in this report as "suggested stream flows." 

In discussing the subject of water availability, the region can be arbitrarily divided into three 
areas; (1) the Yellowstone River Basin, (2) the main stem Missouri upstream from Oahe 
Reservoir, and (3) the Western Dakota tributaries. 



IV-40 



(a) Yellowstone River Basin. -The Yellowstone River and its tributaries are largely 
free-flowing, unregulated streams. The major exception is the Wind-Bighorn River which has 
impoundments. Two of these reservoirs, Boysen and Yellowtail Reservoirs have a combined 
storage capacity of 1,918,000 acre-feet. These reservoirs contain the major portion of the surface 
water that could be made available for coal development in the Yellowstone River Basin. In 
addition to this existing source of water, the potential of supplying water from three 
hypothetical reservoirs was studied. These included two reservoirs, the New Tongue Reservoir on 
the Tongue River and the Moorhead Reservoir on the Powder River to supply some CDP I 
requirements; and one reservoir, Pumpkin Creek, to supply some CDP II requirements. Table 
4-16 shows the amount of water that was determined to be available at particular points of 
diversion and the water requirements for the various CDP's. 

The amounts of water shown as available on table 4-16 are what would have been available 
annually during the driest period of record without any shortages occurring. As the table 
[ illustrates, the water requirements generated by the CDP I and II levels of coal development 
could be met by providing a modest amount of new storage. However, the water requirements 
generated by the CDP III level of development could not be met without depleting flows to a 
level below that necessary to maintain intrinsic stream values unless the conservation water use 
estimates are assumed. Under these conservation water use assumptions, new reservoirs would not 
be required and there would also be an additional 174,500 acre-feet of water available for 
diversion from the Bighorn River at Hardin. This amount of water would exceed that required by 
the attendant municipal and domestic requirements and the irrigation needs associated with 
revegetation of disturbed lands. 

Although it can be concluded that there is sufficient surface water in the Yellowstone Basin to 
supply the needs of coal development up to the year 2000, it must be recognized that other 
water demands, particularly those for new irrigation supphes, will compete for this water. 
Therefore, the Yellowstone Basin should be considered an area where available stored water is 
scarce. 

It has been estimated that there is up to 3 million acre-feet of water in the Upper Missouri 
River Basin'' that could be made available for use without conflict with existing and developing 
uses. Through the construction of major reservoirs on the Yellowstone River and its tributaries, 
possibly 2,000,000 acre-feet of this water could be stored and made available for use in the 



7 
The Upper Missouri River Basin includes all the area that drains into the Missouri River above Souix City, lovifa. 



IV-41 









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lV-42 



Yellowstone Basin. Any amount used in the Yellowstone Basin would of course not be available 
for use downstream. The environmental impact of such storage reservoirs is unknown, but it is 
believed by many to be unacceptable. 

(b) Western Dakota Tributaries .—The Western Dakota tributaries, even with new storage, can 
provide only minimal amounts of water when compared to the Yellowstone Basin or the main 
stem Missouri. Table 4-17 lists the potential reservoir sites on selected tributaries and the 
amounts of water that could be made available from them. It should be noted that the storage 
capacities required are very high compared to the amount of water that would be available on an 
annual basis. The environmental impact of building these reservoirs is unknown. However, it is 
believed to be one of the least acceptable water supply alternatives considered. 

(c) Main stem Missouri River.— Unlike the Yellowstone Basin, the Missouri River main stem 
has an abundance of stored water, some of which may be made available for coal development 
purposes. Three large reservoirs, Ft. Peck, Sakakawea, and Oahe have a total storage capacity of 
66,600,000 acre-feet (table 4-18). 

The average annual flow at Oahe, the dam furthest downstream, is 18,525,000 acre-feet. Of 
this amount, at least 3 million acre-feet could be made available for coal development without 
competing with existing or anticipated uses. Diversions of water from these reservoirs in the 
amounts studied would have relatively Uttle impact on the existing aquatic habitat when 
compared to diversions in the Yellowstone Basin. 

Figure 4-6 shows the amount of water that would be diverted from Lake Sakakawea in the 
year 2000 to supply the various CDP's. 

(d) Deep Ground H^a/er. -Recent studies have indicated a potential for development of deep 
ground-water supplies from the Madison Group, a deeply buried limestone aquifer. These rocks 
underlie the entire Powder River Basin of Montana and Wyoming and are exposed on the flanks 
of the surrounding mountains. 

Much of the Madison formation and underlying carbonates contain water of fair to moderate 
water quality (total sohds 1,000-2,000 milligrams per Uter). Because of the cost of drilhng wells 
and the presence of liigh sodium concentrations in most of the water analyzed, the use of these 
deep ground-water supplies for irrigation is questionable. In general, the water does not meet the 
U.S. Public Health Service Standards (1962) for use on interstate carriers, but it is used for 
municipal water supply in several towns of the region, including Midwest, Newcastle, Upton, and 
Osage. With treatment, this water would be suitable for industrial uses. 

IV-43 



Table 4-\l .—Water available from Western Dakota tributaries 









Water available 




Reservoir 


Total storage 


providing suggested 


River basin 


site 


capacity 


instream flows 






(acre-feet) 


(acre-feet per year) 


Little Missouri 


Marmarth 


504,000 


26,000 




Medora 


332,000 


54,000 




Wagon Creek 


230,000 


25,000 




Beaver 


89,000 


2,000 




Mill Iron 


45,000 


5,000 


Knife 


Broncho 


305,000 


17,000 


Heart 


— 


— 


Negligible 


Cannonball 


Mott 


230,000 


13,000 




Thunderhawk 


216,000 


12,000 




Cannonball 


172,000 


22,000 


Moreau 


Bixby 


253,000 


23,000 



*Diversion from reservoir in all cases. 





Table 4-\8.— Main stem Missouri River storage capacity 






Reservoir 


State 


Capacity in acre-feet 


Average annual 


Dam 


Total 


Holdover 


flow (acre-feet) 


Ft. Peck 
Garrison 
Oahe 


Ft. Peck 

Lake Sakakawea 
Lake Oalie 


Montana 
North Dakota 
South Dakota 


18,900,000 
24,200,000 
23,500,000 


10,900,000 
13,400,000 
13,700,000 


6,838,000 
16,952,000 
18,525,000 



Major ground-water development from the Madison Group should it occur, would to a 
considerable extent, consist of mining a resource because use may exceed recharge. If wells are 
put down near the center of the basin, where most of the strippable coal occurs, major water 
development will probably not have any significant effect on recharge areas for many years. As 
mining of the water from the Madison occurs, the artesian head will decline, pump hfts will 
continue to increase, and the cone of influence of the well field will enlarge. As an example, in 
the Midwest, Wyoming area, major water development from the Madison fonnation has been 
under way since 1917 when the Tisdale well (T. 4 IN, R. 81W., Sec. 16), yielding more than 
4,000 gpm (gallons per minute) was completed. A total of 14 wells have been drilled in this area 
to supply water for the oil industry. The deepest well is 10,040 feet and its original yield was 810 
gallons per minute. Yields of wells in this area initially ranged from 430 gallons per minute to 
more than 9,000 gallons per minute. Available data show seven wells averaging 3,800 gallons per 
minute. 

IV-44 



690 



660 
630 
600 
570 
540 
510 
480 
450 
420 
390 
360 
330 
300 
270 
240 
210 
180 
150 
120 
90 
60 
30 



WATER USE 

COAL GASIFICATION 



ELECTRICAL POWER 
GENERATION 





COP I 



COP II 



COP III 



Figure 4-6. Water diverted from Lake Sakakawea for coal conversion facilities in North Dakota-Year 2000. 



A word of caution is necessary with respect to this source of water for coal conversion use. 
Substantial study should be undertaken prior to development to assess the effects that mining the 
Madison aquifer will have on shallow ground-water supplies, ground-water recharge capability, 
and hence, domestic water supplies. Of particular concern is the continued availability of 
adequate supplies of water for both municipal and agricultural use in the Black Hills (South 
Dakota) region. 



IV-45 



4-9. Water Costs. -{a.) Surface Water.— The main variables affecting the cost of surface water 
are: (1) whether water can be taken without constructing a new reservoir (either from an existing 
reservoir or a diversion without storage); (2) the distance the water must be conveyed by 
aqueduct; (3) the amount of pumping required; and (4) the total amount of water moved 
through the pipeline— since economies of scale may result in lower cost for larger aqueducts. 

On the average, surface water for the North Dakota plant sites will be less expensive than 
surface water supplied to the Montana or Wyoming sites (table 4-19). Since Lake Sakakawea is an 
existing water source, new impoundments are not necessary. Less pumping will be required due 
to the terrain of the land in North Dakota and the shorter distance from the lakes to the sites. 

Table 4-\9. -Water supply systems costs by CDP. * 





Water 


Total* 


Range 


Average 




supplied 


capital 


of cost 


costs 




thousands of 


costs 


dollars per 


dollars per 




acre-feet 


$ milUons 


acre-foot 


acre-foot 


CDP I (Mont./Wyo.) 


101 


50 


63-115 


82 


(N. Dak.) 


23 


7 


38 


38 


CDP II (Mont./Wyo.) 


371 


503 


47-310 


147 


(N. Dak.) 


354 


286 


35-222 


90 


CDP III (Mont./Wyo.) 


802 


1,105 


47-378 


147 


(N. Dak.) 


686 


444 


40-199 


77 



*A11 cost data for choice No. 1 for each CDP as analyzed by Water Work Group. 

In North Dakota, as more water is supplied, the average cost per acre-foot declines. Most of the 
plant sites in either CDP II or CDP III are clustered together. Thus, capital costs or pipeline 
mileage increases very Uttle. In Montana and Wyoming, the additional plant sites in CDP III are 
much farther away from possible diversions and may require more pumping; consequently, 
capital costs increase substantially with the quantity of water supplied. 

Table 4-20 shows the costs of supplying water to the various powerplants and gasification 
plants in the three CDP's. The two choices shown are based on alternate aqueduct systems. 

(b) Ground Water.— T\\q supply systems developed for each CDP consider only surface water 
as a possible water source; however, ground water has been discussed as a possible alternative. 
There are four variables which affect the cost of ground water from the Madison: (1) the depth 



IV-46 



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acre-feet/ 
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IV-47 



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acre-feet/ 
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IV-48 



of the aquifer, (2) the depth below the surface to which the water will rise under artesian 
pressure, (3) feasible withdrawal rates, and (4) the cost of treatment. The nature of the solids 
dissolved in the Madison aquifer water makes it unsuitable for use in coal conversion facilities. 
However, with treatment, the water would be considered a high-quahty water supply probably 
exceeding the quality of most NGP surface water suppHes. 

Recent studies indicate that within the Montana and Wyoming portions of the study area 
where the ground water may be available, it would cost on the average of $39 per acre-foot to 
bring it to the surface. In comparing the cost of ground water to the cost of surface water in 
Montana and Wyoming, only those plants within 30 to 40 miles of the point of diversion could 
obtain surface water at less cost than deep ground water. 

A comparison of surface water costs to ground-water costs are shown in table 4-21 for three 
selected powerplant sites. Similar relative costs would be found throughout the Powder River 
Basin. 

Table 4-2\.— Comparison of water costs* CDP II 









Surface** 


Surface 


Ground § 


Identification 


Surface' 


Surfaced 


water 


water 


water 


number 


water 


water 


unit 


annual 


annual 




source 


amount 


cost 


cost $ 


cost $ 


1 


Moorhead 












Reservoir 


12,000 


89 


1,070,000 


759,000 


2 


Bighorn River 


12,000 


144 


1,730,000 


794,000 


2 


Yellowstone 












River 


12,000 


162 


1,940,000 


812,000 



*Assumes 1,000 MW powerplant— 77 percent capacity factor. 

I From Water Work Group draft report. 

$ Assumes 12,000 acre-feet per year for 1,000 MW plant when surface water is used, 
ground-water plant treating water will use somewhat less— 9,000 to 10,000 acre-feet per year. 

**From Water Work Group draft report— lowest price of choices offered. 

§ Assumes treatment of lime softening, polymer, and acid addition water cost of $50 per 
acre-foot. Based on total dissolved soUd content of water tested in existing wells. No. 1 is 18 
miles north of Gillette, No. 2 is 25 miles east of Hardin, Montana, and No. 3 is 8 miles northwest 
of Moorhead, Montana. 



(c) Effect of Water Cost on Development.— It is possible that the projected cost of water will 
be high enough to affect the extent of coal development. To evaluate that issue, a calculation of 



IV-49 



the percentage of water costs to total value of gas produced was made. For the most intensive 
water user-30,000 acre-feet per year at $350 per acre-foot-the annual water costs were 12.5 
percent of the gross revenues (assuming gas sold for $ 1 per thousand standard cubic feet. If it is a 
high proportion, there are other available methods— ground water, dry cooling, etc.— which may 
lower total water costs. Thus, water costs will certainly affect the level of water use and probably 
plant location as well. 

4-10. Issues Which may Influence Water Cost, Availability, or Use. -(a) Agricultural and 
Industrial Competition for Water.— Energy companies have purchased partial water rights, options 
on water rights, and sometimes the entire ranch or farm, in an effort to obtain access to water. 
When energy companies purchase water riglits which have previously been exercised for 
irrigation, they are in direct competition with agricultural and industrial uses of water. This 
competition occurs today because of the limitations of the existing supply systems. However, as 
previously discussed (sec. 4-7), there may be enough total water flowing through the region to 
satisfy the coal development hypothesized for any of the profiles and to supply an undetermined 
amount of agricultural depletions by year 2000. The principal condition to this statement is that 
in the Yellowstone Basin new storage supplies and possible aqueduct systems will have to be 
constructed. 

Even though sufficient water may be available to meet both future agricultural and industrial 
demands, the price of water will affect its uses. Existing sources, such as converting irrigation 
water to industrial use can supply water at costs much less than the expected costs from new 
supply systems. There is an incentive for industry to buy the less expensive water, which may 
reduce some agricultural activity. This would induce the states, who control the water, to make a 
choice pertaining to the best use of water. 

(b) Indian Water Rights. -The resolution of Indian water rights may have significant impact 
upon NGP water availability. It is difficult at this time to predict the effect and outcome of this 
issue. First, the priority of Indian water right is contested by the states and some non-Indian 
water users. Interpretation of priority ranges from the time the Indians settled the land to the 
date the reservation was established. In addition, the quantity of water reserved is contested. 
Most Indians claim it is all water flowing on, by, or througli the reservation. A thorough 
discussion of this problem is contained in the separate report entitled "Declaration of Indian 
Rights to the Natural Resources in the Northern Great Plains." 



IV-50 



(c) Article X of the Yellowstone River Compact .—According to Article X of the Yellowstone 
Compact, the transbasin diversion of water from the Yellowstone Drainage Basin can occur only 
with the concurrence of the signatory states— Wyoming, Montana, and North Dakota. This 
provision was not completely adhered to in the profile analysis since two plants (in CDP III) 
supplied with Yellowstone Basin water were sited outside basin boundaries— both south of 
Gillette, Wyoming. 

However, if coal development occurs south of Gillette and if the Article X provision is to be 
observed, water will have to be provided from some source other than that proposed in the 
profile analyses. 

The two principal alternative sources for surface water are either Oahe Reservoir or the Green 
River. Water from Oahe will be more expensive than water from within the basin (table 4-22), 
but it does not violate the Compact. Diversion of water from the Green River, a tributary of the 
Colorado River, to the Yellowstone Basin will aggravate the salinity and related problems of the 
Lower Colorado River Basin. 

Another alternative water source is ground water. If a sufficient quantity is available in the 
Gillette area, its cost is much less than any surface water diversion. 



Table A-21.—Cost of providing water to selected 
plant sites by alternative conveyance systems 



Conveyance route 


Average cost per 
acre-foot, dollars 


(In-Basin) 




Miles City to south of Gillette 
Bighorn Lake to south of Gillette 


232 
286 


(Out of basin) 




Green River to south of Gillette* 
Oahe to south of Gillette 
Ground water 


233 
294 

55 



*Analysis done by private consultant. If done with same 
assumptions as Bureau of Reclamation used for other 
alternatives, costs would be substantially higher. 



IV-51 



4-11. Impacts of Water Development .—{di) Water Quality.— 

(1) Present conditions. -The headwaters of most streams in the study area, particularly 
those originating from snowmelt in the mountains of Wyoming and Montana, have excellent 
water quality. The available data indicate degradation of the chemical and physical quahty as 
streams progress downward, resulting from natural hydrogeologic conditions and mans' uses. 

Except in a few locaUzed areas, the water quality remains satisfactory for irrigation, 
livestock watering, recreation, fish and wildlife, municipal, and industrial purposes. The few 
severe local problem areas are usually associated with high levels of activity; municipal or 
agricultural activity, located on depleted or low-flowing streams, and occur on a seasonal 
rather than year-round basis. 

Natural degradation in stream quahty can most easily be described by changes in such 
physical and chemical parameters as temperature, sediment, and dissolved solids. Temperatures 
increase as a stream proceeds downstream and the water receives increased exposure to solar 
radiation and absorbs heat. Likewise, sediment and dissolved sohds generally increase as 
streams proceed toward their mouth. Erosion and subsequent siltation are significant natural 
problems in the Northern Great Plains area. 

These natural changes are also reflected in the biological activity of the aquatic ecosystem. 
A cold water ecosystem, commonly referred to as a trout stream, exists in the upper reaches of 
most Northern Great Plains streams. The lower reaches, because of higher temperatures, more 
sediment, and elevated levels of dissolved materials, generally have a warmer water ecosystem, 
and in some cases are characterized by more pollution-tolerant species, such as catfish and 
goldeye fish. However, this warm water ecosystem is often more complex and varied than is 
the colder water ecosystem. 

Agricultural and municipal activities also affect water quahty in the Northern Great Plains. 
Agricultural influences on water quahty consist primarily of depletion of streamflows, return 
flows of irrigation water, crop and pasture land erosion, and feedlot wastes. Sediment, 
nutrients, and dissolved solids in irrigation return flows to streams have various concentrations 
depending on farm and water management practices. Average TDS (total dissolved sohds) 
concentrations ranging between 1,000 and 2,500 milhgrams per hter have been measured in 
the Powder, Heart, Knife, Cannonball, Belle Fourche, and Cheyenne Rivers. Concentrations 
within this range can be detrimental to crops, aquatic hfe, public use, and industrial use in 
coohng, boiler water, and food processing. 

IV-52 



Suspended sediment concentrations and loads at a given site vary v^^idely throughout the 
year. The sediment load is normally light in the upper reaches of the major streams, but 
increases in the middle and lower reaches. While erosion is a significant natural pollution 
problem, disruption of the land surface due to tilling the soil, grazing, construction activities, 
and surface-mining activities can and do significantly increase erosion rates. 

Washout of feedlot wastes contributes bacteria and organic nutrients to the stream which 
results in depletion of dissolved oxygen and increased bacteria concentrations. These 
pollutants can cause changes in the types of aquatic organisms found in the stream and later its 
recreational and esthetic value. 

Wastes generated from municipalities generally contain organics discharged from sewage 
treatment facilities, and solids washed by runoff from streets and construction sites. These 
sources contribute suspended and dissolved sohds and a variety of nutrients, such as nitrates 
and phosphates, to the receiving stream. 

The average dissolved oxygen level for all stream locations sampled in the Northern Great 
Plains area ranges from 8.5 to 12 milligrams per Hter. However, a marked reduction in oxygen 
levels has been found during the summer months below some municipal waste water outfalls 
and in some reaches with low flows resulting from diversions and natural conditions. A zero 
dissolved oxygen concentration has been recorded for the Heart River near Dickinson and for 
the Missouri River at Bismarck. 

Water temperatures naturally vary significantly from the high mountain streams to the lower 
streams and reservoirs of the plains. Significant water depletions contribute to the increased 
temperatures because the lower volume is heated more quickly by solar radiation. Tlie effect 
of diversions and return flows on stream temperatures is more noticeable in summer months 
when solar radiation and water demands for domestic uses, irrigation, and industry are high. 

Data on existing concentrations of trace elements in the Northern Great Plains are very 
limited. Trace elements such as mercury, lead, flourine, boron, and so forth, are of importance 
because of their harmful effects on crops, livestock, aquatic hfe, and humans. All activities 
which cause the concentration of dissolved sohds to increase can potentially increase the 
concentration of trace elements. The limited available data indicate that harmful 
concentrations of trace elements are not present in Northern Great Plains streams. 



IV-53 



Table 4-23 presents a water quality summary for major streams in the Northern Great 
Plains. A more extensive summary and discussion on the existing water quality of the region is 
available in the NGPRP Water Quality Subgroup Report. 

The present emphasis of the Federal and state pollution control programs is to clean up 
effluent discharges generally referred to as point sources. Regulation of discharges of 
municipal, industrial, and feedlot wastes has resulted in an overall improvement in water 
quahty and will continue to be effective in controlhng water pollution. The pollution problems 
caused by such activities as land surface disruption, stream dewatering, and ground-water 
contamination are not easily abated by conventional water treatment devices and will require 
an extended effort to control their potential pollution effects. 

(2) Potential changes in water quality.— Changes in water quahty are quite likely should 
development occur at levels described by CDF's II and III. The extent of this change will 
depend on the type of environmental regulation and planning instituted prior to development. 
Analysis to date shows very minor or no changes in water quality resulting from development 
at the CDF I level. The analytical tools used for analysis lack sensitivity to accurately predict 
the changes in water quality from a single mine or industrial plant. Therefore, the local impacts 
which may result from low-level coal development are not predicted by these tools. 

Surface Mining Impacts.— The surface mining of coal is one of the major activities which 
can cause changes in water quality. Removal of water which infiltrates active mines may 
cause pollution if adequate treatment is not practiced. Runoff from disturbed areas, 
inadequately treated, will contain sediment, dissolved solids, trace elements, and possibly 
nutrients. Strip mining, which breaks up and exposes large amounts of earth material, 
increases the concentration of dissolved salts, nutrients, and trace elements in ground water, 
which then may flow into a nearby stream. 

Recent sampling of shallow ground water at mines near Colstrip and Decker, Montana, 
have indicated the pollution potential. Data from the Colstrip area show relatively high 
concentrations of calcium, magnesium, sulfate, and total dissolved sohds in waters which 
drain from spoil banks. In the same area, concentrations of two trace elements in spoil bank 
waters (manganese and lead) were found to exceed the U.S. Fubhc Health Service drinking 
water standards. ^The drainage from strip mining activity in the vicinity of Colstrip appears 
to contribute to significant increases in total dissolved solids in surface water (a rise from 



IV-54 



Table 4-23. Water quality summary 





Temp 


DO 


BOD 


pH 


Flow 


TDS 


T-NO3 


T-PO4 


Trace elements 


Total 


Storage location 


SS 


asN 


NH3 


asP 


Pb 


Cu 


Hg 


F 


Se 


Al 


B 


Zn 


hardness 




C 


mg/l 


mg/l 


units 


cfs 


mg/l 


mg/l 


mg/l 


mg/l 


mg/l 


ug/l 


ug/l 


ug/l 


ug/l 


ug/l 


ug/l 


ug/l 


ug/l 


mg/l 


Bighorn River 








































at Bighorn, Mont. 








































Maximum value 


27.2 


^ 


_ 


8.5 


23,000 


836 


21,100 


0.50 


_ 


_ 


_ 


_ 


_ 


700 


_ 


_ 


270.0 


- 


643 


Minimum value 


0.0 


- 


- 


7.0 


612 


471 


42 


0.01 


- 


- 


- 


- 


- 


200 


- 


- 


30:0 


- 


169 


Average value 


12.8 


- 


- 


7.7 


4,249 


608 


4,088 


0.18 


- 


- 


- 


- 


- 


400 


- 


- 


133.5 


- 


338 


Tongue River at 








































Miles City, Mont, 








































Maximum value 


29.4 


_ 


_ 


8.8 


4,139 


816 


_ 


0.10 


_ 


_ 




_ 


_ 


800 


- 


- 


1,250.0 


- 


568 


Minimum value 


0.0 


- 


- 


6.9 


16 


262 


- 


0.01 


- 


- 




"" 


- 


200 


- 


- 


10.0 


- 


104 


Average value 


10.5 


- 


- 


79 


594 


570 


- 


004 


- 


- 






- 


361 


- 


- 


137.3 


- 


324 


Powder River at 








































Moorhead, Mont. 








































Maximum value 


28.5 


12.4 


10.0 


8.5 


4,600 


4,080 


_ 


_ 


0.61 


320 


50 


30.0 


0.9 


2,200 


11.0 


~ 


448.0 


32.0 


1,220 


Minimum value 


0.0 


5.2 


0.6 


7.4 


8 


676 


- 


- 


0.00 


0.0 


0.0 


0.0 


0.0 





0.0 


- 


241.0 


0.0 





Average value 


10.5 


9.0 


3.0 


8.0 


642 


1,552 


- 


- 


0.09 


0.54 


1.0 


10.4 


0.2 


500 


3.7 


- 


274.8 


16.0 


615 


Yellowstone River 








































near Sidney, Mont. 








































Maximum value 


24.4 


12.6 


3.3 


8.9 


65,240 


655 


15,500 


0.69 


0.26 


2.70 


00 


10.0 


- 


800 


_ 


200.0 


260.0 


0.0 


403 


Minimum value 


0.0 


7.4 


0.9 


6.9 


1,149 


230 


167 


0.00 


0.00 


0.01 


0.0 


0.0 


- 


100 


- 


100.0 


20.0 


0.0 


90 


Average value 


11.3 


98 


1.8 


7.8 


14,527 


460 


2,308 


0.20 


0.06 


0.32 


0.0 


2.5 


- 


449 


~ 


150.0 


146.4 


0.0 


245 


Knife Rivet at 








































Hazen, N. Dak. 








































Maximum value 


24.0 


_ 


_ 


8.3 


5,930 


1,510 


_ 


2.40 


_ 


_ 


_ 


- 


- 


900 


- 


- 


1,300.0 


- 


530 


Minimum value 


0.0 


- 


~ 


7.0 


13 


204 


- 


0.00 


- 


- 


- 


- 


- 





- 


- 


0.0 


- 


81 


Average value 


9.1 


- 


- 


7.9 


392 


1,004 


- 


1.15 


- 


- 


- 


- 


- 


400 


- 


- 


263.2 


- 


320 


Heart River at 








































Mandan, N. Dak. 








































Maximum value 


25.0 


16.2 


8.9 


9.0 


_ 


2,280 


_ 


_ 


_ 


0.76 


- 


_ 


- 


- 


- 


- 


- 


- 


515 


Minimum value 


0.0 


3.7 


0.8 


7.0 


- 


175 


- 


- 


- 


0.01 


- 


- 


- 


- 


- 


- 


- 


- 


110 


Average value 


10.3 


9.6 


2.9 


8.0 


- 


844 


- 


- 


- 


0.11 


- 


- 


- 


- 


~ 


- 


- 


- 


290 


Cannonball River at 








































Breien, N. Dak. 








































Maximum value 


24.0 


_ 


_ 


8.3 


2,770 


1,960 


_ 


4.80 


_ 


0.21 


_ 


_ 


_ 


1,400 


- 


_ 


860.0 


_ 


720 


Minimum value 


0.0 


- 


- 


7.2 


15 


285 


- 


1.00 


- 


0.0 


- 


- 


- 


100 


- 


- 


0.0 


- 


140 


Average value 


10.2 


- 


- 


7.8 


414 


1,139 


- 


2.68 


~ 


0.02 


- 


- 


- 


546 


- 


- 


346,0 


- 


429 


Missouri River at 








































Bismarck, N. Dak. 








































Maximum value 


22.0 


14.3 


6.0 


8.6 


36,400 


653 


_ 


_ 


0.90 


0.07 


60.0 


50.0 


_ 


700 


0.1 


59.0 


360.0 


42.0 


706 


Minimum value 


0.0 


6.1 


0.0 


7.7 


1,040 


268 


- 


- 


0.00 


0.01 


4.0 


10.0 


- 


450 


0.01 


9.0 


91.0 


2.0 


4 


Average value 


8.3 


10.6 


1.1 


8.3 


18,239 


425 


- 


- 


0.24 


0.04 


33.6 


22.0 


- 


519 


0.2 


37.3 


217.0 


20.4 


212 


Belle Fourche River 








































near Elm Springs, 








































S. Dak. 








































Maximum value 


29.0 


12.9 


16.0 


9.0 


8,560 


4,820 


13,600 


8.40 


0.72 


0.3 


11.0 


80.0 


0.3 


2,700 


- 


179.0 


710.0 


40.0 


2,440 


Minimum value 


0.0 


4.8 


0.2 


6.5 


2.8 


512 


7 


0.11 


0.01 


0.0 


0.0 


5.0 


0.0 


300 


- 


0.0 


80.0 


0.0 


300 


Average value 


9.7 


9.2 


3.3 


7.7 


361 


2,071 


1,537 


3.25 


0.24 


0.53 


09 


34.2 


0.1 


608 


- 


114.5 


342.2 


18.9 


1,110 


Cheyenne River at 








































Edgemont. S. Dak. 








































Maximum value 


25.0 


11.8 


9.4 


8.4 


609 


7,100 


_ 


2.00 


2.40 


5.80 


10.0 


75.0 


0.3 


1,100 


20.0 


100.0 


770.0 


490.0 


3,100 


Minimum value 


0.0 


0.2 


0.5 


4.2 


0.3 


695 


- 


0.00 


0.00 


0.00 


0.0 


3.0 


0.1 


200 


0.0 


0.0 


10.0 


20.0 


260 


Average value 


10.4 


8.6 


29 


7.7 


61 


3,551 


- 


0,44 


0.35 


0.49 


2.1 


25.5 


0.2 


600 


5.1 


50.0 


346.9 


132.1 


1,476 



Legend; DO — Dissolved Oxygen 

BOD— Biochemical Oxygen Demand 
pH-lonic Balance, 1-7 acid, 8-14 basic 
Flow/cts— Flow, cubicfeet per second (ftVs) 
TDS-Total Dissolved Solids 



SS— Suspended Solids Cu— Copper 

T-NO3 as IM-Total Nitrate as Nitrogen Hg-Mercury 

NH3— Ammonia F — Fluorine 

T-PO4 as P— Total Phosphate as Phosphorus Se— Selenium 

Pb— Lead Al— Aluminum 



B— Boron 

Zn-Zinc 

mg/l— Milligrams per liter 

ug/l— Micrograms per liter 

- No Data Available 



lV-55 



about 2,200 to 3,500 milligrams per liter). In the Decker area, the major chemical 
consittuents in water draining into the mine are sodium, bicarbonate, and sulfate. Since the 
ground water in the area contains little, if any, sulfate, a sizable amount must be leached as 
a result of the mining operations. The relatively strong mineralization of overburden, 
demonstrated by the occurrence of saline seeps in the area, is a major if not the primary 
cause for changes in the area's ground-water quality. Although no conclusive demonstration 
is available to indicate the direct effect of mining operations on surface water quahty, these 
shallow ground-water studies indicate to some extent the potential for surface water quahty 
degradation. 

An increase in the concentration of dissolved solids, including trace elements and 
nutrients in ground water will, in many cases, be transported to a stream or river by 
underground flow. Mines located close to streams have the greatest potential for rapid 
degradation of surface water quahty. 

The persistent nature of this type of pollution and the difficulity in abating it poses one 
of the most difficult environmental problems for mining operations. Further data collection 
and analysis is needed to better understand the potential for water quahty problems 
resulting from mining and to evaluate schemes for minimizing water quality degradation. 

Coal Gasification and Powerplant Impacts. -Coal conversion facihties also have the 
potential to cause water quality changes. These industrial plants will utilize water, 
consumptively reducing flows and thereby lowering the transport and waste assimilative 
ability arf the river. Effluents containing elevated temperatures, dissolved soUds, trace 
elements, and certain organics from gasification may cause water quality degradation. 
Industrial plants can be designed to use a minimum amount of water and have very little, or 
no effluent. Most "no discharge" plants presently utihze large solar evaporation ponds for 
ultimate waste disposal. The impact of these ponds on ground water, wildhfe, and water 
fowl are very site oriented, but are generally considered preferable to operations that 
discharge into a nearby stream, provided no substantial seepage occurs. 

Water quality changes that have been quantitatively evaluated by the NGPRP to date have 
assumed that the industrial plants will use larger than necessary amounts of water and will 
therefore have an effluent. Should smaller quantities of water be used and plants built 
having no discharges, overall regional water quality changes resulting from coal-energy 



IV-56 



conversion plants will probably be less. Of particularr significance is that water supply 
streams such as the Bigliom will have greater flows as less diversion will be needed, while 
effluent-receiving streams such as the Tongue and Powder Rivers will have lower flows as 
they would no longer receive effluents. If nondischarge plants become the rule, nonpoint 
sources of pollution associated with coal development will become increasingly important, 
as effluents will diminish. 

One water quality parameter, TDS (total dissolved soHds), can be sufficiently modeled so 
that rough estimates of the degree of water quality change can be made. The projections are 
based entirely on estimates of consumptive use of water by coal-energy conversion plants 
and do not include TDS increases caused by runoff from disturbed areas, leaching of mine 
spoils, or any increase in agriculture or other water use. These other sources of TDS are not 
incorporated into the projections because they could not be quantified; however, they are 
important to water quahty. These projections are based on numerous assumptions and need 
refinement as more and better data are compiled. 

Powerplants of 1,000 MW size are assumed to have an annual discharge of 5.000 acre-feet, 
thereby concentrating the TDS by a factor'* of 3.8 times the intake concentration. 
Gasification plants ('250 milhon cubic feet per day) are assumed to range in discharge from 
20,000 to 10,000 acre-feet reflecting a degree of uncertainty about their operation. The 
concentration factor for gasification plants then has a range of 1.5 to 3.0. These numbers, 
along with estimates of existing TDS concentrations in rivers of the region, are used to make 
the TDS projections. 

These projections indicate that the average annual concentration of total dissolved solids 
in the Missouri River at Bismarck, North Dakota, would increase for CDF III from 436 
milligrams per liter to between 465 and 500'' milligrams per liter or approximately 7 to 15 
percent. For CDF II level of development, projected increases for the Missouri River at 
Bismarck are between 445 milligrams per liter, a 2 percent increase and 470 milligrams per 
Uter, an 8 percent increase. The large volume of water which flows in the Missouri River 
below Garrison Dam— approximately 15 to 16 million acre-feet per year— has a tremendous 
dilution capabihty which is the principal reason for the small increases in these TDS 
projections. 



8 Intake volume = Concentration factor 

Effluent volume 
9 

Includes the effects of a reduction in flow in the Missouri River at Bismarck resulting from development of the Garrison 
Irrigation Project. 

IV-57 



Table 4-24 shows the results of TDS projections for some other potentially impacted 
rivers of the region. In the case of the Powder and Knife Rivers a decrease in the TDS 
concentration is indicated as being possible. This finding results from using a water supply 
source with a relatively low TDS concentration (Bighorn River and Lake Sakakawea) and 
discharging into water with a relatively high TDS concentration. The low TDS concentrating 
factor for gasification plants of 1.5 is another major reason for the results which indicate a 
possible improvement in TDS concentration in the Powder and Knife Rivers. 



Table A-24. -Projected annual average total dissolved solids concentrations 

resulting from assumed discharge from 

coal gasification and power generation plants 





Historical 






average 


Range of TDS projections 


River and location 


concentration 
(mg/D* 


(mg/1) 




CDP 11 


CDP III 


Tongue River 








at Miles City, Montana 


560 


700-790 


760-910 


Powder River 








at Moorhead, Montana 


1,552 


1,410-1,590 


1,280-1,770 


Yellowstone River 








near Sidney, Montana 


460 


480-490 


510-530 


Knife River 








at Hazen, North Dakota 


1,004 


870-1,100 


790,1,150 


Heart River 








near Mandan, North Dakota 


844 


860-870 


850-890 


Missouri River 








at Bismarck, North Dakota 


436 


. 445-470 


465-500 



^Milligrams per hter 

Note; These projections are based on numerous assumptions and need refinement as more and 
better data are compiled. Therefore, this table should be used only to make broad inferences 
about potential TDS concentrations. 



The TDS projections indicate that of the rivers analyzed, the Tongue River has the 
greatest potential for being impacted by discharges from coal conversion faciUties. Projected 
increases in TDS range from 25 to 41 percent for CDP II and 36 to 62 percent for CDP III. 
This potential TDS increase is due in part to the relative low dilution capacity (flow) in the 
Tongue River compared with the Yellowstone and Missouri Rivers. Also, the Tongue River 
historically has low TDS concentrations compared to the other Yellowstone and Missouri 



IV-58 



River tributaries analyzed, and therefore discharges with high TDS concentrations will result 
in a greater change in the Tongue River than in the Powder, Knife, and Heart Rivers. 

TDS projections for annual low-flow conditions, show an even greater increase in TDS 
concentration. For example under CDP III and flow conditions which occurred in 1966, the 
Tongue River at Miles City is projected to have an annual TDS concentration from 880 to 
1,120 milligrams per liter. For CDP II, the projected TDS range is from 800 to 960 
milligrams per hter. The average TDS concentration during 1966 was 645 milligrams per 
hter. For the once-in- 10-year low-flow conditions, again 1966, the Yellowstone River at 
Sidney is projected to have TDS increases from 500 to 510 milligrams per hter for CDP II 
and from 540 to 570 milhgrams per liter for CDP III. The average TDS concentration at 
Sidney during 1966 was 491 milligrams per Hter. For more information on these projections 
including monthly projections, the reader is referred to the report of the NGPRP Water 
Quality Subgroup. 

The importance to water users of these increases in TDS concentrations is dependent 
upon many factors which have not been adequately assessed to make any specific 
conclusions. Generally, TDS concentrations in excess of 1,000 milligrams per liter are 
considered adverse for irrigation of many crops but actual limits vary considerably, up or 
down, according to soil composition, drainage, and water management practices. The EPA 
has proposed a maximum acceptable TDS concentration for livestock drinking water of 
3,000 milligrams per liter but higher concentrations are tolerated by livestock in the region. 
Generally, water is considered good for public drinking supphes if the TDS concentration 
does not exceed 500 milligrams per liter but many communities in the region utilize water 
with much higher TDS concentration. 

An important consideration in evaluating the effects of higher TDS concentrations is the 
constituent dissolved solids which comprise the total. Certain constituents such as sodium 
and boron are harmful to crops, and others such as sulfates and chlorides are undesirable for 
pubhc water supplies. Many of the trace elements can be toxic to aquatic life, livestock, and 
humans. The potential for water quality problems from an increase of certain dissolved 
constituents as a result of coal-energy development is unknown and will require further data 
collection and study. Initial work concerning the assessment of potential trace element 
concentration increases in the NGP is being conducted by EPA. 



IV-59 



Sewage Treatment Impacts.— An influx of people, necessary to support development, is 
also a potential source of changes in water quality. Rapidly growing communities 
traditionally have a problem with inadequate sewage treatment faciUties. There is normally a 
lag between the arrival of large numbers of people and the institutional and financial 
framework required to build additional treatment facihties. The associated problems of 
nutrification, dissolved oxygen depletion, and aquatic toxicity resulting from poorly treated 
sewage can cause serious degradation of water quality. This potential water quaUty problem 
will be most serious for rapidly growing towns with moderate to large populations 
discharging to seasonally low-flowing streams. 

Discharges of treated domestic wastes can cause significant depletion of dissolved oxygen 
when the capacity of the stream to biologically assimilate the wastes is less than that 
discharged into the stream. Dissolved oxygen analyses were made for Bilhngs and Miles City, 
Montana, located along the Yellowstone River and for Sheridan, Wyoming, located along 
Goose Creek, a tributary of the Tongue River. These municipalities were chosen because of 
the availability of USGS stream data, and because these sites represent a range of flow and 
population impacts which miglit result from coal-energy development. At all three locations, 
secondary treatment was assumed as defined by EPA.' ° Complete mixing of wastes in the 
stream was also assumed. It was found that during August low-flow conditions, an estimated 
population for Billings corresponding to CDP 111 would not cause a violation of the 
dissolved oxygen standard in the Yellowstone River. Similarly for Miles City no violation of 
the DO (dissolved oxygen) standard was calculated using tlie August instream flow 
requirement (suggested minimum flows used elsewhere in this report) as the low flow for 
that location. Sheridan, Wyoming, located along a low-flowing steam, was shown to have a 
liigli potential for violating the dissolved oxygen standard depending upon the estimated 
influx of people into that city. A population in Sheridan of between 14 and 23 thousand 
with secondary waste treatment is estimated to result in violation of the dissolved oxygen 
standard. For a complete explanation of this analysis, see the NGPRP report of the Water 
Quality Subgroup. 

In general these dissolved oxygen analyses imply that with secondary waste treatment, 
the Yellowstone and Missouri River main stems will not be significantly impacted with 
respect to dissolved oxygen as a result of current population influx estimates and the 



Federal Register, August 17, 1973, vol 38, No. 159, part H. 



IV-60 



aqueduct diversions discussed earlier. Conversely, cities and towns discharging into creeks 
and low-flowing streams of the region can expect to go beyond secondary treatment of 
domestic wastes, or limit the discharge rate, if significant population growth is experienced 
in the area. These areas include such municipahties as Sheridan, Buffalo, Gillette, Dickinson, 
and potentially many others. 

In this analysis of DO impacts, an important assumption has been made which should be 

emphasized again, wliich is that secondary treatment as defined by EPA is assumed for all 

municipal waste discharges. Since the secondary treatment standard is required for all 

municipalities by July of 1977, this assumption is reasonable. But the reahties of financing 

the upgrading of existing treatment facihties may cause a lag in implementation of this 

standard. This situation is especially true for small, rapidly growing communities which 

require substantial revenue to provide secondary treatment for future populations but lack 

the economic base upon which to generate the required dollars. The existence of such 

communities will most likely be fostered by rapid coal-energy development. If so. State and 

Federal Governments must recognize this problem at an early stage and formulate plans to 

deal with the local needs. Otherwise, the pollution of streams and rivers will be more drastic 

than revealed by this report. 

(b) Shallow Ground-water Impacts.— Coal development in the Northern Great Plains will 

impact shallow ground water in both a physical and a chemical manner. Water levels in wells close 

to mine operations will be lowered as long as mining continues, and even after mining, flows into 

some wells may remain low. Pollution of ground water from leaching of spoils may occur, but 

would probably have only local effects. Wells drilled in mine spoils will produce less water of 

lower quahty than before mining. The means and costs of avoiding these impacts are largely 

unknown. The complexity of the shallow aquifer system makes it difficult, however, to 

accurately predict the quantitative impacts of the exploration, extraction, and use phases of coal 

development without first having an accurate geohydrologic description of each site. As a result, 

the discussion presents only ranges in or types of impacts as they have been measured at a few 

sites or as may be possible under theoretical conditions. 

The most significant impacts on the shallow ground-water system may come from mining. 
Exploration, primarily through drilhng, will encounter situations where unplugged wells will flow 
and where uncased holes will serve as interconnections between aquifers containing water of 



IV-61 



varying quality. Mining, and particular surface mining, will serve both to lower the local water 
table and to alter the chemical quahty of the water passing through the disturbed overburden or 
spoils. The coals form all or a significant part of the shallow aquifers in the region. Removal of 
the coal thus removes part of the water-carrying strata. The resultant open trench in the active 
coal mine will thus serve as a point of discharge for the shallow aquifers interrupted by the 
trench. The water seeping into the trench may amount to a few hundred thousand gallons per 
day which can be pumped out to facilitate mining. The trench acts as a large well causing a 
lowering of the water table, usually to a distance of from 1 to 6 or so miles from the mine, 
depending upon the geologic structure of the area. The vertical extent of water-table drawdown 
will not be greater than the depth of the trench (currently up to about 200 feet) and this amount 
will normally be found only adjacent to and on the downstream side of the trench. The 
drawdown could reduce the amount of water available to wells completed in the coals and could 
at least require relocation of pumps and deepening of wells. 

As spoils material are returned to the trench, the water table will begin to rise. After mining is 
completed, the depth to water will be about equal to that encountered prior to mining, as long as 
the final elevation of the rehabilitated terrain remains about the same as existed prior to mining 
and the areal extent of the mining is relatively small. If the final surface elevations of the terrain 
are significantly below the original elevations, internal drainage could occur and salt 
accumulation caused by evaporation could be a problem. If extensive mining is practiced over the 
region, areas of recharge may be disturbed and regional water tables may be changed over a large 
area. There is no experience to date with large-scale mining over an entire coal basin and accurate 
predictions of the impact of mining on the shallow ground-water system require extensive 
site-specific investigations that are not yet available. 

The total effect of surface mining on the physical water system will be related to the depth of 
the operation and the total horizontal extent of the operation. For example, at Decker, Montana, 
a new mine has been initiated with an open cut about 12,000 feet long and 200 feet deep. It is 
estimated that the current operations intercept, through the coal and associated aquifers, from 
200,000 to 400,000 gallons of water per day. Water-level declines radiate between 3/4 and 1-1/2 
miles from the mine after about 15 years of mining. The impact situation at Decker. may be 
limited by faulting (vertical displacement) of the coal aquifer. 



IV-62 



When the spoils material or overburden is replaced in the mine, it assumes a porosity and 
permeability dissimilar to that possessed by the undisturbed material. Generally, the spoil 
material has a higher porosity and lower horizontal permeability than the overburden had prior 
to mining. Tliis ijidicates that there is more void space and generally greater downward dispersion 
of water entering the material. Because there is likely to be less concentration of water in 
horizontal aquifers within the replaced overburden, wells drilled into it may not have the ability 
to produce water at as high a rate as that prior to mining. 

The spoils materials provide a source of dissolved solids for the percolating ground waters that 
apparently exceeds the sources available to waters in undisturbed overburden and coal. Increases 
in dissolved solids contents of water percolating through spoils have been shown in laboratory 
experiments and in the field. 

Major leachable ions include sodium, calcium, sulphate, and carbonate. In the case of limited 
sampling at Colstrip, most ions measured in water collected from spoils showed an increase 
attributable to seepage through the spoils. 

The concentrations were generally below recommended limits for beneficial uses with the 
exception of arsenic, lead, manganese, and sulphate, which appeared to consistently exceed the 
PubHc Health Service Drinking Water Standards. It should be noted that conclusive data are 
limited and that this comparison was made only for drinking water standards. 

Under certain circumstances, water carried in the coal is similar to water passing througli 
charcoal filters— it is relatively clean and can in fact be somewhat filtered. When that water can 
no longer flow through the coals because of removal of those coals, but instead passes through 
broken sand, shale, and clayey spoils materials, it can be reasoned that the water will pick up 
minerals. It might also be reasoned that the rate of pickup will decrease with time. However, 
water from old spoils placed some 45 to 50 years ago at Colstrip, Montana, have suggested that 
the poor quality of these older waters is equivalent to those waters collected from much younger 
spoils at the same site. A decrease in the amount of leaching of ions with time has not yet been 
noted. 

In the cases of mining and use, the probability of chemical deterioration of ground water is 
high. However, the lateral and vertical extent of such deterioration remains unknown. 
Unfortunately, no measurements were made in the past. Similarly, the length of time that 
increased leaching will take place is not known. Therefore, it is difficult to predict what, if any, 



IV-63 



long-term or areally ranging chemical problems coal development may cause users of these 
shallow ground waters. Intuitively, it appears that the small yields produced by these aquifers 
indicate that travel velocities of the waters are or will be moderately slow and that contaminants 
may not range great distances. However, with slow velocities, recovery rates of the water table 
would likewise be slow and the physical impact of mining on ground water may outweigh, in the 
short term, the chemical impacts. 

The cost of avoiding these impacts include the costs of tests and measurement of spoil 
properties and aquifer hydrology, special handling of spoils for purposes such as: (1) maintaining 
aquifer flow in the same strata, (2) insuring sufficient permeabihty (transmitivity) to insure 
continued flows, (3) placement of less saline spoils at aquifer layers, (4) treatment of surface 
configuration, and (5) insuring control of leaching or preserve recharge, revegation, and other 
surface treatment to insure desirable runoff or recharge rates. Adequate information for 
preplanning of mining is at present largely nonexistent, and the costs of any of the 
above-mentioned measures is unknown. 

(c) Impact of Water Development on Land Resources. —The suggested streamflow estabhshes a 
criteria for estimating the impact of flow depletions on the aquatic ecosystem. All specific CDP 
water supply alternatives examined in this report met the instream flow requirements except the 
Hardin aqueduct diversion for CDP III development. Although meeting the NGPRP instream flow 
requirement is not certain to maintain the existing aquatic life, the result of not meeting them 
indicates a tremendous potential for inducing stress and therefore altering the type of aquatic 
exosystem. 

There are other basic environmental considerations that must be made in evaluating impact of 
water supply alternatives particularly those utilizing aqueducts and reservoirs. 

Most of the land disturbed during the construction of a buried pipeline aqueduct may be 
restored within a few years, although its value as wildlife habitat may be different than it 
originally was. A longer term loss of grazing and wildlife uses from aqueducts would result from 
placement of a roadway along the aqueduct route to facilitate maintenance of facihties. Crossing 
through streams would result in temporary degradation of downstream water quahty and loss of 
habitat for some aquatic organisms. 

With reservoir construction, there is a direct irreplaceable loss of land due to permanent 
flooding. As an example, 556,000 acres of Missouri River bottomlands and adjacent uplands were 



IV-64 



lost when Lake Sakakawea was formed. Seasonal flooding of downstream riparian habitat, 
flushing of stream channels, water quality characteristics, and other parameters are modified 
downstream subsequent to impoundment. Some of these changes may be beneficial while others 
are generally detrimental to existing fish and wildlife resources. 

Generally, aqueducts diverting water from an existing storage facility exert less severe impacts 
on terrestrial wildlife than do new impoundments. Impacts on aquatic resources are often 
dependent on the quantity of water left in the stream to meet instream flow requirements and 
maintain riparian habitat and water quality. 



IV-65 



3. Air Resources 

4-12. Ambient Air Quality .-The Northern Great Plains is relatively free of large-scale air 
pollution problems. Extremely clean air is a trademark with visibiUties of 50 miles, or more, 
commonplace. The "big sky" phenomenon is treasured by people who live in the region and by 
those who visit it. A discussion of the area plus an assessment of the coal development impacts 
upon it follows. 

The frequency and intensity of air movement in the study area (fig. 4-7) should result in good 
dispersion conditions. Average annual wind speeds range from 8 to 14 miles per hour, with 
Casper, Wyoming, being the highest (fig. 4-8). Winter chinook winds occurring near the eastern 
side of the Rocky Mountains may last for several days and reach 25 to 50 miles per hours. 

The dispersive characteristics of a plume are also dependent upon the mixing layer height, 
which is that layer of air next to the earth's surface where vertical mixing occurs. Shallower 
layers imply a greater potential for high air pollution concentrations. A summary of mixing 
heiglits encountered in the study area is presented in table 4-25. 

Table 4-25.— Northern Great Plains mean mixing heights (meters)* 





Annual 


Winter 


Spring 


Summer 


Autumn 


Morning 


300-400 


300-400 


400-500 


300 


300 


Afternoon 


1,400-1,600 


600-1,000 


2,000-2,400 


2,000-3,000 


1,400-2,000 




(N. Dak., 


(N. Dak., 


2,800 








S. Dak., 


S. Dak., 


(S. Dak. 








and Nebr.) 


Mont.) 


and Wyo.) 








1,000-2,400 


1,000-1,200 










(Wyo. and 


(Wyo.) 










Mont.) 











*To convert meters to feet multiply by 3.28. 

In general, the worst dispersive conditions occur in the morning and during the winter 
afternoons. Little data is available on the frequency and extent of temperature inversions that 
cause localized stagnant airmasses and concentrate air pollutants. Data to define this phenomena 
for five locations in the NGP are being collected and will be available in 1976. 



IV-66 




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The annual mean relative humidity for the study area is 60 percent. The study area receives 
between 60 and 70 percent of total possible sunshine. These are important factors because the 
conversion of SO2 to sulfate is beUeved to be a function of relative humidity and the converstion 
of hydrocarbons and nitrogen oxides to photochemical oxidants occurs in the presence of 
sunlight. 

Presently the major manmade sources of air plllution in the NGP are farming, grain processing, 
power generating, oil refining, and production of lumber. The total emissions are small when 
compared to emissions in the Los Angeles Basin, the industrial areas of Ohio or Pennsylvania, or 
even the metropohtan Denver area. An estimate of the amount of five common air pollutants 
emitted in 1972 is shown in table 4-26 A comprehensive description of air quaUty in the NGP is 
not possible because at present there are only 30 air quality monitoring stations in the NGP. This 
system has been augmented with nonurban monitoring stations, and the additional data will be 
available in 1975. 

Figures 4-9 through 4-13 show pollutant concentrations from selected sites througliout the 
NGP. Also shown on these figures are the primary and secondary NAAQS (National Ambient Air 
Quality Standards) and state air quality standards. Primary standards have been established for 
those pollutants that are hannful to human health. The effects of these levels of pollutants occur 
primarily in the respiratory, pulmonary, and circulatory systems. Secondary standards have been 
established to protect plant and animal hfe, and materials. 

4-13. Impact of Coal Conversion on Air Quality .-{2) Primary Impacts. —Federal and State air 
pollution control laws require attainment and maintenance of air quality at a level that will not 
adversely impact human health and welfare, animal or plant life, or materials. Therefore, it must 
be assumed that the emissions from coal conversion facilities or pollutants from other sources 
will be controlled so as not to violate these laws. For this reason, the possibihty of adverse 
environmental effects from air pollutants is not predicted unless future research indicates that the 
present standards are not adequate, or that compounds that are harmful are not covered by a 
standard. 

The conversion of coal to produce electricity or synthetic natural gas will result in the 
production of many kinds of air pollutants, including particulates, sulfur oxides, nitrogen oxides, 
Hydrocarbons, and carbon monoxide. Major pollutants emitted from a powerplant will be 
particulates, sulfur oxides, and nitrogen oxides. Major emissions from gasification plants appear 



IV-67 






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to be hydrocarbons with additional quantities of particulate, sulfur oxides, and nitrogen oxides 
from onsite steam generation. The potential harmful effects of these pollutants were recognized 
by Congress in passing various Federal Clean Air Acts. As a result of the 1970 Act, the 
Administrator of EPA promulgated primary and secondary standards (NAAQS) for the 
pollutants, that, in his judgment, have an adverse impact on health and public welfare. These 
standards are shown in table 4-27. Trace elements such as mercury, lead, beryllium, arsenic, 
flourine, cadmium, and selenium are emitted from coal conversion facilities. Chemical reactions 
which occur in the air result in the conversion of sulfur dioxide to sulfates (such as sulfuric acid) 
and nitrogen oxide to nitrates. Some of these elements or compounds can be harmful to human 
health, to animal and plant hfe, and to materials. There are no Federal standards applicable to 
coal conversion facilities for any of these pollutants at the present time. Some of the NGP states 
have standards for sulfates, lead, beryllium, and flourine. 

In discussing the impacts of coal development on NGP air quahty, a comparison to these 
standards wih be made. 

To attain and maintain the NAAQS a variety of State and Federal regulations on existing and 
new emission sources have been adopted. New NSPS (New Source Performance Standards) which 
are applicable only to new sources have been promulgated. Those standards (table 4-28) apply to 
all fossil-fuel fired steam generating plants larger than about 25 MW (megawatts) whose 
construction began after August 17, 1971 (lignite plants are exempt from the NO^ NSPS). 

These standards would require a powerplant burning a 10 percent ash, 1.0 percent sulfur, 
9,000-Btu-per-pound coal to control particulate emissions by 99 percent, sulfur oxide emissions 
by 40 percent, and nitrogen oxides emissions by 30 percent. Control of particulate matter may 
be achieved by liighly efficient electrostatic precipitators, wet scrubbers, or fabric filters. Sulfur 
oxides emissions may be controlled via wet scrubbers using an alkahne media or via catalytic 
oxidation. Nitrogen oxides emissions are normally controlled by preventing the formation of NO 
by lowering the combustion temperature. 

Existing sources of pollution in the states must meet regulations contained in SlP's (State 
Implementation Plans). The principal purpose of these plans is to attain and maintain ambient air 
quahty standards. 

There are three other related air quality standards which are relevant to this discussion. First, 
as part of the SIP process each state projects its anticipated emissions through the year 1985 and 



IV-69 



Table 4-27. -NAAQS (National Ambient Air Quality Standards) 



Pollutant 



Primary standard 



Secondary standard 



1. Surfur oxides 



2. Particulate matter 



3. Carbon monoxide 



4. Photo chemical oxi- 
dants (corrected 
for NO 2 and SO 2 
interference) 

5. Hydrocarbons (cor- 
rected for CH4) 

6. Nitrogen oxides 
(as nitrogen 
dioxide) 



80 ug/m^ (0.03 ppm) annual arith. mean 
365 ug/m^ (0.14 ppm) max 24 hr. cone, 
not to be exceeded more than once a year. 

75 ug/m^ annual geom. mean 260 ug/m^ 
max 24 hr. cone, not to exceeded more 
than once a year. 

10,000 ug/m^ (9 ppm) max 8 hr. cone, not 
to be exceeded more than once a year. 

40,000 ug/m^ (35 ppm) max 1 hr. cone, not 
to be exceeded more than once a year. 

160 ug/m^ (0.08 ppm) max 1 hr. cone, not 
to be exceeded more than once a year. 



160 ug/m^ (0.24 ppm) max. 3 hr. cone. (6 
to 9 a.m.) not to be exceeded more than 
once a year. 

100 ug/m^ (0.05 ppm) annual arith. mean. 



1,300 ug/m^ (0.5 ppm) max 
3 lir. cone, not to be 
exceeded more than once 
a year. 

60 ug/m^ annual geom. j 

mean*, 150 ug/m^ max 24 ' 
hr. cone, not to be ex- ' 

ceeded more than once a year; 

Same as primary 

Same as primary 
Same as primary 



Same as primary 



Same as primary 



*To be used as guide in assessing State Implementation Plans. 

NOTE: 

ppm = parts per million 

ug/m^ = micrograms per cubic meter. 



IV-70 



estimates air quality resulting from such projections. If the analysis shows that National Ambient 
Air Quality Standards may be exceeded, the state must develop a 10"-year plan to insure that 
standards are maintained. Montana, North Dakota, and Wyoming have counties in the coal areas 
which are subject to these plans. Second, a Federal indirect source regulation has been 
promulgated and states are now in the process of adopting their own. The regulation requires 
evaluation of the impact of major highway proposals, airport proposals, and certain other 
facihties such as shopping centers, before an application to construct can be approved. 

Table 4-2S. -NSPS standards 





Allowable pounds/ 10*^ Btu 




Coal 


Oil 


Gas 


Particulate 
S02(sulfur dioxide) 
NO^ (oxides of nitrogen) 


0.10 
1.20 
0.70 


0.10 
0.80 
0.30 


0.10 
0.20 



Lastly, the issue of air quality deterioration of clean air quality areas is being examined. The 
Clean Air Act of 1970, as amended, required a SIP to contain regulations to prevent significant 
deterioration where air quality is better than that required by the national standards. These 
regulations could be the single most important regulation both to the Nation and to the NGP in 
terms of maintaining excellent air quality. Present plans call for designating three types of 
geographical zones. The standards for these three zones are shown in table 4-29. 

In Zone 1 there will be essentially no decrease in air quality allowed, in Zone 2 a moderate 
decrease will be allowed, and in Zone 3 the air quality can be degraded to the secondary 
standard. 

Each state will be responsible for zoning itself and enforcing the standards. This means that the 
people of each state can maintain the quality of air however they choose as long as it does not 
threaten human health and welfare. 

To estimate the effect of plant emissions upon present NGP air quaUty, pollutant 
concentrations were calculated using a computer model. The annual and 24-hour particulate, SOo 
(sulfur dioxide), oxides of NO^ (nitrogen), and HC (hydrocarbon) concentration estimates were 
made using a computer program similar to that pubUshed by Martin' ' (1971). Martin's program 



'^Martin, D., 1971, "An Urban Diffusion Model For Estimating Long Term Average Values of Air Quality" 7. Air Poll. 
Control Assoc. 16, (I), pp. 16-19, January 1971. 

IV-71 



was modified to Burt' ^ (1973) to consider the effects of elevated terrain, to utilize Briggs' ^ 
(1969, 1970, 1971, and 1972) plume rise equations, and to provide a significant computer 
printout which gives concentrations at specified grid points located along 16 radials fixed by the 
common 16 wind directions, N. NNE, NE, ENE, and so forth. A detailed description of the 
model as it has been modified, and the computer code is given by Burt' ^ (1973). A complete 
description of the technique plus the assumptions are contained in the Atmospheric Aspects 
Work Group Report.'" The estimates were based on powerplants that are either under 
construction, applying for construction permits, or are being proposed and have associated 
environmental studies in progress, and a hypothetical gasification plant. It was assumed that 
emissions from each powerplant would be equal to, but not exceed, NSPS. Emissions from the 
hypothetical gasification plant were estimated from data suppUed by companies planning the 
construction of coal gasification faciUties. 

Table 4-29. -Proposed significant air deterioration 





ug/m^ increase over 1 974 levels 


ug/m^ 




Zone 1 


Zone 2 


Zone 3 


Particulate matter 








Annual 


5 


10 


75 


24-hour 


10 


30 


150 


Surfur oxides 








Annual 


2 


15 


80 


24-hour 


5 


100 


365 


3-hour 


25 


700 


1,300 



NOTE: ug/m^ is micrograms/cubic meter. 

There, are no synthetic natural gas plants in existance or under construction in the United 
States at the present time. Therefore, emission estimates were obviously based upon design data 
only. 



12 Burt, E. W., 1973, "Description of Terrian Model (C7M3D)" (Manuscript in Preparation) MDAD, SRAB, Modeling 
Application Section, U.S. E.P.A., Research Triangle Park, North Carolina 2771 1. 

'^Briggs, G. A., 1969, "Plume Rise" U.S. A.E.C., Critical Review Series TID-25075, National Technical Information Service, 
Springfield, Virginia 22151. 

'^Briggs, G. A., 1971, "Some Recent Analyses of Plume Rise Observations", pp. l029-\032, Proceedings of the Section 
International Clean Air Congress edited by H. M. Englund and W. T. Berry, Academic Press, New York City. 

l^Briggs, G. A., 1972, Discussion on Chimney Plumes in Neutral and Stable SuTToundings, Ati^ospheric Environment, \o\. 6, 
pp. 507-510, July 1972. 

^^"Atmospheric Aspects Work Groups Report" Northern Great Plains Resources Program, 1974, unpublished document. 



IV-72 



The combined capacity of these plants (fig. 4-7) correspond closely to the CDP I, therefore 
impacts from these plants can be construed to be representative of CDP I impacts. That is the 
primary reason for the selection of these plants to be studied. Portions of these plants are 
operational today with the plant expansions being designed to become operational in the near 
future. 

Table 4-30 presents the results of the modeling estimates for annual concentrations. 

Table 4-30.— Estimated annual air quality concentrations* 





Maximum concentration, ug/m^ 


Plant 


Particulate 


SO2 


NO, 


Colstrip 


0.2 


2A 


1.4 


Naughton 


0.7 


8.2 


6.0 




**6.0 


**68 


**50 


Bridger 


0.2 


2.5 


1.4 


Underwood 


0.04 


0.4 


0.4 


Leland 


0.03 


0.5 


0.3 


Gentleman 


0.04 


0.5 


0.3 


Young 


0.03 


0.3 


0.3 


Wyodak 


0.1 


1.3 


0.7 



*Background pollutant concentrations not included. 
**With terrain considered. 

NOTE: ug/m^ is micrograms per cubic meter. 



Table 4-31 lists the "worst case" maximum predicted ground-level 24-, 3-, and 1-hour 
concentrations. 

All of the concentrations hsted in tables 4-30 and 4-31 are representative only of the 
contribution from the plant, that is, no existing pollutant concentrations (background) are 
included. Background must be added to obtain an estimate for comparison against relevant 
ambient standards. 

Figures 4-14 and 4-15 illustrate the comparison between the appUcable air quality standards 
and the estimated impact upon air quality as a direct result of the powerplant. It should be noted 
that these figures indicate the worst that could happen but do not include the frequency of 
occurrence of such an event. The probability of occurrence is determined by the frequency of 
occurrence of a given meteorological condition. 



IV-73 



Table 4-31K— Estimated short-term air quality concentrations' 





Maximum 24-hour 


Maximum 3- and 1-hour SO2 




concentrations 


concentrations 


Plant 


Particulate 


SO2 


3 -hour 


1-hour 


Colstrip 


0.8 


9 


385 


624 


Naughton 


0.8 


10 


270 


440 


Bridger 


0.7 


8 


220 


360 


Underwood 


0.4 


5 


120 


194 


Leland Olds 


0.3 


3 


84 


140 


Gentleman 


1.0 


12 


80 


128 


Young 


0.4 


5 


170 


278 


Wyodak 


0.3 


3 


125 


200 


Gasification 






1,360 


— 


plant 






(Hydro- 
carbons) 





*A11 data in micrograms per cubic meter (ug/m-'). 

The modeling analysis of the eiglit powerplants for SO2 and particulates show that (fig. 4-14 
and 4-15) no state or Federal standards will be violated. 

The predicted annual average SO2 concentrations in the vicinity of the Naughton plant 
approach the Wyoming and Federal standards. When corrected to Wyoming elevation, the 68 
ug/m^ (micrograms per cubic meter) concentration equates to about 55 ug/m^ . These values 
compare with the Wyoming standard of 60 ug/m^ and the EPA primary standard of 70 ug/m-^ . 

It appears that there are three atmospheric conditions that may result in conditions tliat could 
violate standards. The first situation occurs when there are extremely stable atmospheric 
conditions with steady winds for 8-10 hours directing the plume toward elevated terrain. This 
causes the pollutants to impinge at the elevated point thus causing a possible violation. The 
second condition, termed fumigation, occurs when there are extremely stable conditions that 
result in a localized build-up of pollutants above the earth's surface followed by a rapid change to 
an unstable atmosphere which would cause these pollutants to settle on the earth's surface. The 
tliird condition is when extremely unstable wind conditions exist and the plume is directed to the 
ground very near the point of emission. Available meteorological data for the sites studied 
indicate that these conditions occur very infrequently and they may not persist for sufficient 
duration to cause a violation of a standard. 

Diffusion modeling provided air quaUty estimates of about 800 ug/m^ (micrograms per cubic 
meter) and a 3-hour hydrocarbon concentration associated with the gasification plant. This value 



IV-74 



EXPECTED TO BE ADDED BY SELECTED POWER PLANTS 



24 HOUR 



NEBRASKA & EPA PRIMARY STANDARDS . 



MONTANA STANDARD 



NEBRASKA, NORTH DAKOTA & EPA SECONDARY STANDARDS 100- 



..0 8 . Jil, 0.7 4 3 

-CZZ3 EZZ2 IZZZ3 ■' ' ' ■ -■ ■ ■ - 



4 5 

POWER PLANTS 



150 



ANNUAL 



MONTANA. NEBRASKA & EPA PRIMARY STANDARDS . 



.75 _ 



NEBRASKA NORTH DAKOTA & WYOMING STANDARDS , 



^ 



'aV^VTA ^^ 



0.04 



003 



0.1 



1. COLSTRIP- 2060MW 

2. NAUGHTON - 1570MW 

3. BRIDGER - 1500 MW 

4. UNDERWOOD 972 MW 



4 5 6 7 8 

POWER PLANTS 

5. LELAND OLDS -656 MW 

6. GENTLEMAN - 650 MW 
7 YOUNG - 635 MW 

8. WYODAK-330MW 



Figure 4-14. Maximum ambient particulate concentrations. 



1000 



900 



AT SELECTED POWER PLANTS 
1300 I 



1 HOUR 



NORTH DAKOTA STANDARD. 
MONTANA STANDARD 



.216 



.650 




3 4 5 6 

POWER PLANTS 



900 



S800 



O500 



100 




NEBRASKA. WYOMING & EPA STANDARDS - 



3 HOUR 




3 4 5 6 

POWER PLANTS 



450 



350 



< 

S 200 

O 



100 



24 HOUR 



NEBRASKA & EPA STANDARDS . 



.365 



MONTANA, NORTH DAKOTA & WYOMING STANDARDS . 



-260 



10 



\77Z\ V77A VTZk r^^ .J^ 



4 5 6 

POWER PLANTS 



''/' r / y ^ I ,, , , , 



COLSTRIP- 2060 MW 
NAUGHTON- 1570 MW 



BRIDGER - 1500 MW 
UNDERWOOD - 972 MW 



2 50 



ANNUAL 

NFRRASki A FP4 STiun^RPS . ,ftO 




NORTH nAKfira a Wyoming STANDAHns , fin 


MONTANA STANDARD ci? 






2.1 


8.2 

Y//A 


2.5 0.4 0.5 0.5 3 ^^ 

f-r-r^ c-r-^ ,-y-r^ r,-^^ .^^„ l/Z/.l 



4 5 6 

POWER PLANTS 



5. LELAND OLDS -656 MW 

6. GENTLEMAN - 650 MW 



YOUNG - 635 MW 
WYODAK - 330 MW 



Figure 4-15. Maximum ambient SO2 concentrations. 



is well over the allowable standard of 160 ug/m^ . Therefore, the proposed gasification plants will 
have to control their hydrocarbon emissions to a further degree than preliminary planning would 
indicate. This control can be accomplished by incineration, adsorption, absorption, or catalytic 
conversion. Draft environmental impact statements that have been released indicate that 
hydrocarbon emissions will make essentially no contribution to air quality concentrations. 

An estimate of the pollutant concentrations compared to standards was not made for specific 
plants in either medium or high CDP's because of a lack of specific plant data and sites specific 
meteorological data. An air quality and meteorology monitoring network has been established to 
compliment the existing data gathering efforts. Monitoring is being conducted at 22 new sites in 
the region in addition to the 30 sites presently existing. This new data, combined with existing 
regional meteorological data gathering activities, will enable the use of a regional model approach 
which is necessary to assess the interactions of several plants upon some remote area. 

Although modeling was not performed, the pollutant emissions introduced into the 
atmosphere by power and gasification plants at each of the three CDP levels for five pollutants 
was estimated. Table 4-32 hsts those emissions. For comparison purposes, refer to the previously 
presented emissions in table 4-26. 

(b) Secondary Impacts.— Only the direct environmental impacts of the coal conversion 
facihties were factored into the modeling effort. Secondary impacts may have a significant 
impact upon air quality. Mining activities and the attendant population growth are the major 
identifiable "secondary impacts." It is extremely difficult to quantify secondary impacts. 
However, work is being done to provide data which may enable quantitative assessment. Only a 
qualitative discussion may be presented at this time. 

It is known that an increase in particulate matter, in the form of fugitive dust, will occur as a 
result of any strip-mining activity. Also because of the activities of people required to support the 
coal conversion facility, there will be an increase in emissions resulting from their activities. 

The effect of the increased atmospheric loadings of particulate matter, especially the 
significant increase in fine particles and gaseous pollutants, upon visibility is extremely difficult 
to predict. It is logical to postulate that a decrease in visibility will occur, but the extent of that 
reduction cannot be quantified with our present data. It is the fine particles, such as those in the 
0.1 to 1.0 micron (radius) size range, that dominate the light scattering phenomenon and hence 
degradation of visibiUty. This is the size of particulates that will be emitted to the greater extent 



IV-75 



because most present day pollution control techniques are relatively inefficient collectors of 
submicron particles. 



Table 4-32.— Estimated emissions from projected coal conversion facilities 

in tons per year 





Powerplants 


Coal gasification plants 




Low CD? 


Interme- 
diate CDP 


High CDP 


Low CDP 


Interme- 
diate CDP 


High CDP 


Particulate 
1985 
2000 


41,700 
99,330 


41,700 
142,180 


41,700 
142,180 






13,370 
30,560 


38,200 
78,310 


Sulfur oxides 
1985 
2000 


500,600 
1,192,750 


500,600 
1,707,240 


500,600 
1,707,240 






150,710 
344,480 


430,600 
882,730 


Nitrogen oxides 
1985 
2000 


291,850 
695,330 


291,850 
995,260 


291,850 
995,260 






72,520 
165,760 


207,200 
424,760 


Hydrocarbon 
1985 
2000 


8,780 
20,910 


8,780 
29,930 


8,780 
29,930 






609,490 
J, 398, 120 


1,741,400 
3,569,870 


Carbon dioxide 
1985 
2000 


29,620 
70,570 


29,620 
101,010 


29,620 
101,010 






5,320 
12,160 


15,200 
31,160 



About 431,000 tons of particulates are presently emitted each year in Montana, North Dakota, 
and Wyoming. The low, intermediate and high CDP's would increase this loading by 18, 31 and 
42 percent, respectively, by the year 2000. The coal bearing area, however, is much smaller than 
the three states and the increased loading would be many times what is not introduced into the 
area. The degree to which the plants were concentrated would have a strong influence on the 
reduction of visibihty. After data now being collected are analyzed, the extent to which the 
problem could be reduced, can be better estimated. 

(c) Potential Constraints to Coal Conversion .-Vresent law requires that ambient air quality 
standards must be attained and maintained throughout the NGP. Air quality impacts as a result 
of the construction of powerplants at the CDP I level would appear not to affect maintenance of 
the standards. However, some possible interpretations of the "significant deterioration" issue 



IV-76 



would constrain development. Plant sitings, plant size, and degree of emission control may be 
influenced by this resolution. 

Technology for control of hydrocarbon emissions from gasification plants must be improved if 
hydrocarbon air quality standards are to be maintained. The degree of the control technology 
will be one factor in the determination of the extent of development. 

Development at CDP II and III levels may be constrained by air quahty standards. 

4-14. Research and Analysis Needs. -Some research needs are necessarily regional in nature 
while others have national impacts. It is anticipated that through the NGPRP some data may be 
collected to provide input to those national needs. 

The significant increase in SO2 emissions, hence atmospheric loadings, creates the potential for 
a decrease in the pH, that is, the measurement of acidity of rainfall in the Northern Great Plains 
and midwestem states. The amount of this pH decrease cannot be determined with any degree of 
accuracy on a theoretical basis without making a wide set of assumptions. Measurement of pH at 
a number of rain collection stations in the NOP should be initiated. In so doing, baseline data 
may be gathered with subsequent measurements identifying the impact of the projected coal 
conversion facihties. Tliis is potentially serious because should the pH drop significantly, acid 
rains could be created with many associated corrosive and health impacts. 

The potential for photochemical oxidant formation in the vicinity of coal gasification 
complexes appears to be significant. These oxidants are serious in causing eye irritation, 
pulmonary tract damage, and a deleterious affect on vegetation. The Los Angeles-type brown 
smog is a case of photochemical oxidant formation. The combination of hydrocarbon emissions 
from the gasification process, the nitrogen oxides emission from the attendant steam generating 
plant, and a high frequency and intensity of sunliglit in the NGP states provides all the 
ingredients for potential oxidant formation. A network of hydrocarbon, NO^ and oxidant 
ambient air quality monitors should be established in the areas of potential gasification plants to 
obtain baseline data. An ongoing network of oxidant monitoring should continue well into the 
future to determine the impact of the anticipated facilities. 

Effects of the pollutants for which there are Federal standards and of trace pollutants from 
coal conversion facilities upon young vegetation in reclaimed areas should be evaluated. A 
research study being c6nducted by the National Environmental Research Center at Corvalhs, 
Oregon, will address this topic to a certain degree. More effort should be directed toward this 
activity. 

IV-77 



The aspect of the increased particulate matter in the atmosphere acting as additional cloud 
condensation nuclei should be studied. Both increased and decreased precipitation have been 
theorized as a result of this phenomenon. This is important because of its potential for regional 
climatic change. 

The atmospheric concentrations and effects of increased CO2 (carbon dioxide) emissions 
should be evaluated. Monitoring sites could be identified where CO2 levels would be measured 
over a long period of time. Tliis is one of the causes of the theorized world-wide "greenhouse 
effect." 

Health and welfare effects of increased atmospheric loadings of sulfates and nitrates should be 
studied. A program similar to the Community Health Environmental Surveillance Study might 
provide beneficial information. Sulfates and possibly nitrates are being shown to have serious 
health effects on humans and animals. 

The increased levels of fine particulate matter in the atmosphere and the potential light 
attenuation and solar insolation effects should be the subject of further in-deptli research. There 
is not sufficient information available to predict how serious the reduction in visibility would be 
and there is insufficient knowledge on potential regional and world-wide climatic changes. 

The identification of the fate of trace elements during the combustion of coal is being studied. 
Much more work needs to be done on this to determine their potential impacts and to determine 
the presence and concentrations of trace elements in the coal throughout the NGP. This could be 
very important in determining which coals should be mined to minimize trace element pollution. 

There are preliminary indications that trace elements tend to be preferentially concentrated in 
the smaller particle size range. If this is so, then the health problems caused by small particulates 
may be even more serious than anticipated. A theory of volatihzation and subsequent adsorption 
onto the small particle surface area has been put forth as an explanation. Almost no extensive 
studies have been performed on this topic, but they are needed. 



IV-78 



PART V-THE ECONOMIC, SOCIAL, AND CULTURAL IMPACTS 
OF COAL DEVELOPMENT IN THE NGP 

5-1. Introduction.— Coal development may have a profound impact upon the economy, 
institutional fabric, and social structure of the residents in the Northern Great Plains. It is an 
extremely difficult task to accurately assess what impact coal development will have upon the 
people of the Northern Great Plains. Some impacts are quantifiable, while others can only be 
addressed subjectively. It is in this framework that the economic, social, and cultural impacts are 
addressed. 

Some of the issues to be discussed in this section are: 

—How will coal mining and conversion change the employment patterns and levels in the NGP? 

—How much and how fast will the population of the region grow? 

-How will the population increases effect the availability of housing, educational facihties, 
and municipal services? 

-What tax revenues will be generated by coal development and will they be available in 
sufficient amounts to meet the needs of local and state governments? 

-How will coal development effect the agricultural industry? 

Impacts stemming from increased coal development will touch nearly every sector in the NGP 
study area, be it the economy, government institutions, or the social system. Coal development 
will affect the economy by creating new and expanded job opportunities as well as higher levels 
of income in the region. Population growth associated with coal development will mean 
unprecedented population increases, both in terms of magnitude and the speed with which it will 
occur. Also, the ability of the present institutional structures will be severely tested. Higher levels 
of service will be required as well as new services to meet the demands of the existing and new 
population. CompHcating the increased institutional demands is the potential of time lags 
between when services are needed and new revenues. Social systems will be altered and strained 
as new value systems and new peoples are imposed upon a well-established social system. 
Conflicts and increased social tensions may occur. 

Coal development is a regional problem as it will affect individuals and localities over a wide 
geographic area. Nonetheless, it is the local people and institutions which will have to address this 



problem and resolve the issues. Althougli each community must assess its own special problems it 
is doubtful if many of the localities in the Northern Great Plains are really prepared or capable of 
accomplishing the task. 

Considerable uncertainty remains regarding the socio-economic impacts of coal development in 
the Northern Great Plains. Because of the complex nature of coal development, it is extremely 
difficult to estimate or assess cumulative impacts. However, these impacts may be critical. Is the 
impact of two mines or powerplants in the same area twice as great as the impact of one, or is it 
larger? Furthermore, how adaptable is the socio-economic environment? Do equal increments of 
change require equal adjustments or do they require successively more? It is quite possible that 
the impacts of coal development in the Northern Great Plains may be greater than the projection 
and analytic techniques used have been able to dehneate. 

From within the states of Wyoming, Montana, North Dakota, and Nebraska, 36 counties were 
selected as the "principal impact areas," (see fig. 5-1). Similiarly, from within these impact areas 
a number of communities were designated as "principal impact communities." Common to both 
these "areas" and "communities" is the fact that they contain the heaviest concentration of 
present and proposed coal development activity. Consequently, they will receive the heaviest 
concentration of impacts generated by such activity. 

Many Indian reservations will be affected by coal development. Some contain considerable 
amounts of coal and some is already leased. Consequently, potential coal development impacts 
on Indian peoples was also selected for more detailed analysis. 

The one economic activity having the longest tradition and widest influence in the four-state 
study area is agriculture. Therefore, it too was selected for consideration of the impacts imposed 
by coal development. Within agriculture, labor, water, and land were selected as the most 
meaningful expressions of impact. 

Appropriate economic indicators that were selected for measurement of change within the 
"impact area" and "impact communities" included employment, population, education, and 
housing. These are discussed in the report. 

The intent here is to indicate, on a sample basis, the kind and magnitude of changes that coal 
development may be expected to generate. It is assumed that additional studies that are more 
site-specific, more precise, and more definitive will be needed to support land use planning and 
decisionmaking. Some examples of such follow-up studies also are given. 



V-2 




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5-2. The Principal Impact Area and Changes Expected as a Result of Coal 
Development. -(a) Employment-Employment projections* for the principal impact area within 
the states of Wyoming, Montana, Nebraska, and North Dakota are summarized in table 5-1. The 
increase in employment in these four states between 1970 and 2000 ranges from 28 percent for 
CDP I to 143 percent for CDP III. Total employment under CDP III increases by 148 percent 
within the principal impact area in Wyoming, 159 percent in Montana, 172 percent in North 
Dakota, and 32 percent in Nebraska. 

In the coal sector specifically (table 5-2), total coal-related employment under CDP I would be 
17,000 in 1980, fall to 8,000 by 1985, then climb to 18,000 by year 2000. Approximately 60 
percent of the total direct employment would be operational and 40 percent construction-related 
employment. 

Under CDP II, 23,000 people would be employed in coal-related jobs in 1980 and 85,000 by 
the year 2000. Approximately the same percentage of direct to indirect employment would be 
expected as in CDP I; 2,000 direct operational jobs and 4,000 construction jobs in year 1980 and 
19,000 operation and 5,000 construction jobs by the year 2000. 

Under CDP III, employment would substantially increase; 84,000 people would be working in 
coal-related activities in 1980 and 175,000 by year 2000. Direct operational employment would 
total 10,000 in 1980 and increase to 49,000 by year 2000, while construction employment 
would total 16,000 in 1980 and decrease to 9,000 by year 2000. 

As noted here, growth from operational employment will be strong but reasonably stable over 
the period of development, while construction employment will fluctuate considerably. Large 
construction forces will swell the population in impacted areas, peak, and then decline to zero. 
An example of this wide fluctuation in construction employment is presented in figure 5-2 for 
Campbell County, Wyoming. 

As an indication of the employment that would stem from coal development, in CDP III 
agriculture^ would no longer be the principal basic employment sector in the area. Coal would 
become the dominant sector in both Wyoming and Montana, overshadowing agriculture and 
petroleum in Wyoming and agriculture and manufacturing in Montana. In CDP I and II, coal 
employment would be expected to remain below agriculture employmeq^t. 

The estimates presented reflect direct and indirect service employment for the operational as well as the construction phase 
of development. Employment that would be created by satellite industries that might locate near large gasification or powerplants 
is not included. Therefore, the estimates are conservative. No employment projections for South Dakota are presented because 
the selected principal impact areas did not involve South Dakota. 

2 

Although agriculture presently is the primary source of basic employment in the four states, it is declining in its relative 
importance. During the decade from 1960-70, total agricultural employment declined by more than 30 percent in the four -state 
area. In other industrial sectors, mining gained 3 percent while manufacturing increased by more than 12 percent. 

V-3 



Table S-\ .Total employment-principal impact area 1970-2000 



1970 



1980 



1985 



2000 



All units in thousands 



Montana 


46 


56 


53 


63 


North Dakota 


53 


60 


55 


64 


Wyoming 


42 


48 


51 


54 


Nebraska* 


22 


26 


27 


29 


Total 


163 


190 


186 


209 



CDP II 



Montana 




57 


75 


80 


North Dakota 




60 


71 


105 


Wyoming 




52 


59 


67 


Nebraska* 




26 


27 


29 


Total 




195 


235 


281 



CDP III 



Montana 




76 


88 


119 


North Dakota 




90 


82 


144 


Wyoming 




57 


78 


104 


Nebraska* 




26 


27 


29 


Total 




249 


275 


396 



*The same figures were used for Nebraska in all profiles. 



V-4 



5600 



4900 



4200 



3500 



UJ 

_i 
o. 

O 
UJ 
0. 



O 2800 



UJ 

ffi 

3 
Z 



2100 



1400 



700 




1975 1980 

Source: Bureau of Reclamation (1974) 



1985 



1990 



1995 



2000 



Figure 5-2. Estimated annual average construction employment during construction of facilities for mining, 
electirical plants, and gasification plants, Campbell County, Wyoming 1975-2000 



Table 5-2— Estimated employment related to coal development 
(principal impact area—CDP's I, II, and III) 





CDPI 


CDPII 


CDP III 


Area 


1980 


1985 


2000 


1980 


1985 


2000 


1980 


1985 


2000 



(All units thousands) 



MONTANA: 




















Direct operating 


1 


1 


2 


1 


4 


6 


4 


7 


14 


Construction 


1 


— 


1 


1 


3 


1 


4 


3 


2 


Indirect 


7 


3 


7 


7 


20 


17 


22 


26 


40 


Total 


9 


4 


10 


9 


27 


24 


30 


36 


56 


NORTH DAKOTA: 




















Direct operating 


1 


— 


1 


* 


3 


9 


5 


7 


20 


Construction 


1 


— 


— 


1 


3 


4 


7 


3 


7 


Indirect 


4 


1 


3 


4 


12 


32 


24 


19 


57 


Total 


6 


1 


4 


5 


18 


45 


36 


29 


84 


WYOMING: 




















Direct operating 


1 


I 


1 


1 


2 


4 


1 


7 


15 


Construction 


— 


— 


— 


2 


1 


— 


5 


3 


— 


Indirect 


2 


9 


3 


6 


9 


12 


12 


24 


20 


Total 


3 


3 


4 


9 


12 


16 


18 


34 


35 



STATE TOTALS (Principal im 


pact area) 














Direct (operating and 

construction) 
Indirect 


4 
13 


2 
6 


5 
13 


6 

17 


16 
41 


24 
61 


26 

58 


30 
69 


58 
117 


Total 


17 


8 


18 


23 


57 


85 


84 


99 


175 



*Where estimates are less than 500 they are not shown. Nebraska estimates were never greater 
than 500; therefore, estimates for this State were not included in this table. 



V-5 



Figure 5-3 illustrates the relative magnitude of change in agriculture employment relative to 
coal-related employment in the CDP's. The effects that coal development might have on 
agricultural employment is not portrayed in this illustration, that is, agriculture employment is 
assumed to be the same for each CDP. 

(b) Population .—Population projections in the principal impact area are summarized by year 
and CDP in table 5-3. The total population growth for this area between 1970 and 2000 ranges 
from 19 percent for CDP I to 119 percent for CDP III. Under the assumptions of CDP III, the 
population of the principal impact area will increase from 434,000 to 950,000 between 1970 and 
2000. This would be in marked contrast to the population growth of only 1 percent experienced 
in this area during the decade of the 60's. 

As the data presented in table 5-3 suggests, only a small increase in population in the principal 
impact area is expected to occur in CDP I. Although growth of approximately 5 percent would 
be experienced between 1980 and 2000, most of it is expected to result from noncoal sources, 
since very little expansion of coal mining is assumed after 1980. Consequently, the area should 
return to its historically modest rate of growth after 1985. 

In CDP II, population would escalate to approximately 679,000 by year 2000, representing an 
increase of 56 percent over the impact area's 1970 population. Several factors would account for 
this rather significant growth rate. The principal reason is that CDP II assumes substantially 
greater coal mining beyond the CDP I level for the impact area. In addition, coal gasification is 
introduced in this profile as a source of employment and economic growth. As a result of this, 
and increased coal export, a substantial increase in construction and operating employment and 
associated population growth can be expected. 

This, however, is relatively small when compared to the population growth that would occur 
under CDP III. In this profile, a significantly greater number of coal gasification and export coal 
mines are assumed. As a result, population in the principal impact area would be expected to 
increase by over 100 percent during the 30-year period between 1970 and year 2000. 

Although the CDP's assume that new facilities come on line throughout the study period, 
growth rates in the principal impact areas will vary depending upon the scheduling of coal-related 
developments (see fig. 5-4). For instance, Wyoming, under CDP I, has a projected growth in 
population of 17,000 between 1970 and 1980, and only 8,000 from 1980 and 2000. North 



V-6 



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COAL RE 


LATED EMPLOYMENT- COP 1 















1980 



1985 



1990 
YEAR 



1995 



2000 



Figure 5-3. Coal-related employment as compared to agricultural employment 
principal impact area-Montana and Wyoming* 1980-2000 



I 



900 



800 



700 



600 



< 

O500 

X 



400 



3 

a. 
O 

Q. 



300 



200 



100 











y^ 










CDPIII^r 








J 


y 


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CDP 11 ^^ 






/ 


/ 


.^^ 


III 




^^ 


i^^ 




•^•^* 





















































1970 1975 1980 1985 

YEAR 



2000 



Figure 5-4. Anticipated population in the study area for each CDP. 



Table 5-3. 


-Total population projections, CDP I, II, III- 1980, 1985, 2000 






State totals 
1970 


Principal impact area 




1970 


1980 


1985 


2000 







All units thousands 






CDP I 












Montana 


694 


123 


142 


135 


157 


North Dakota 


618 


147 


163 


145 


162 


Wyoming 


332 


107 


124 


128 


132 


Nebraska* 


1,483 


57 


61 


62 


65 


Total 


3,127 


434 


490 


470 


516 


CDP II 












Montana 






144 


179 


187 


North Dakota 






163 


188 


267 


Wyoming 






131 


145 


160 


Nebraska* 






61 


62 


65 


Total 






499 


574 


679 


CDP III 












Montana 






180 


203 


267 


North Dakota 






243 


217 


386 


Wyoming 






140 


181 


239 


Nebraska* 






61 


62 


65 


Total 






624 


668 


950 



*Identical figures are shown for Nebraska in all profiles because any changes between CDP's 
are so small that the differences are negligable in rounding. 



V-7 



Dakota, because of a projected decrease in construction employment under CDP's I and III, can 
be expected to experience a population decrease between 1980 and 1985 with expansion 
continuing until 2000 but at a much slower rate. 

The economic and social consequences of population changes are discussed in the remaining 
portions of part V. 

(1) Migration. -Lov/ population growth rates in the principal impact areas can be 
reasonably explained by the region's migration pattern. In the recent decade- 1960 to 
1970-45,000 people migrated from the principal impact area. This represents a 10 percent net 
emigration rate for the 10-year period. North Dakota lost the greatest number of inhabitants 
(27,000) followed by Montana (8,000), Wyoming (6,000), and Nebraska (4,000). 

What can be expected in the future is unclear. 

There are a number of considerations regarding migration that cannot be treated adequately 
at this time, such as: 

—Sources of labor both from within and outside the area. 

—Wages necessary to attract workers. 

-Competition for labor and the effects stemming thereform. 

—Socio-economic characteristics of prospective immigrants. 

—Working conditions at the plants and mines, and 

—Numbers of people leaving area because of social and economic dislocation. 

There are indications, however, that only a small labor pool exists within the principal 
impact area. A large number of workers may be induced to migrate into the area and reverse 
the historic trend of net emigration. Although the level of migration depends upon the 
magnitude of development, which varies greatly between CDP, a net increase should occur by 
1980 in the principal impact area. 

(2) Spatial distribution.— Coal development is expected to occur at a significant level in 
only a few of the counties within the principal impact area. Therefore, impacts will be 
concentrated in only a few key locations and not spread evenly over the area. 

The most obvious example of this occurs in Wyoming. Under CDP III in year 2000, 
Campbell County is expected to experience an increase in population of about 64,000, or 
nearly 500 percent. During the same period, Niobrara County, a neighbor to the southeast, is 
projected to experience a decHne in population of about 14 percent. 



V-8 



The isolation of some of the plant and mine locations from urban centers coupled with their 

ultimate size^ raises the possibility of new town developments. Commuting could pose a 

problem in coal development areas like those envisioned in Wyoming where plant and mine 

sites are located in excess of 40 miles from Gillette, the only urban area in the county. 

5-3. The Principal Impact Communities and Changes Expected From Coal 

Development.— Communities within the principal impact areas range from small towns of less 

than 100 people to a few cities'* , the largest of which is Billings, Montana, with a population of 

over 61,000. The typical size of towns in the area ranges between 500 and 3,000, with some 

villages having populations of less than 20. Villages of this size would probably only have a post 

office that serves the farm or ranch community surrounding it and a service station for tourists 

traveling through the area. 

The somewhat larger towns may have a school, post office, and a small business center which 
may consist of only a grocery and hardware store. Little else would be provided leaving the 
residents of these communities heavily dependent upon the larger trade and service centers, for 
example the county seat towns, to satisfy a large portion of their needs. 

Communities, such as Forsyth, Gillette, and Stanton, have been capable of providing most of 
the service needs of the people within their respective area of influence. Services provided include 
such faciUties as churches, a hospital with small staff, secondary wholesale units, and a daily or 
weekly newspaper. Additional services include gasoline service stations, eating and drinking 
establishments, clothing and food stores, repair facihties, movie theaters, and barber shops. A 
variety of professional services including those of optometrists, dentists, and veterinarians 
generally have been provided. 

Many services are provided by nonprofit organizations, such as hospitals, social welfare services 
such as charity, counseling, religious instruction, citizen action. Junior Chamber of Commerce, 
youth groups, and other groups. 

Governmental services provided include police and fire protection, education and welfare, 
sanitation, sewage, as well as parks and recreation facihties. 

The large urban centers hke Billings, Rapid City, and Bismarck offer a wide range of goods and 
services and act as wholesale suppliers to the smaller trade centers. 



A single gasification complex of the size envisioned in this study could induce a population of as many as 7,000 people which 
is about the 1970 population of Gillette. 

other large communities in the principal impact area and their 1970 populations include Bismarck (34,290) and Casper 



V-9 



To finance their public service systems, the communities rely principally upon the property 
tax which is levied and collected by the local governments. Floating revenue bonds or selling 
municipal water are other ways to generate revenues but they are methods generally reserved for 
the larger cities. A small amount of revenues accrue to the local governments in the form of 
reapportioned state tax revenues, but these are generally small and vary considerably with the 
type of tax levied and the individual state tax structure. In addition, revenue sharing is a new 
source of revenues for local governments— two thirds of a state's revenue sharing allocation is 
apportioned to units of local governments. 

As opposed to the rather limited means of financing available to town and city governments, 
state and county governments have a variety of methods that can be used to secure revenues to 
finance their operations. Taxes provide the largest share of state revenues which, to reiterate, are 
reapportioned, in part, back to local levels of government. The types of taxes and the levels of 
government to which they are distributed are presented in table 5-4. 

State revenues are also derived from State and Federal leasing and royalty payments. Federal 
assistance programs (including revenue sharing), and Federal grants. 

In Wyoming, the royalties paid to the State from production of minerals on State lands go to 
the permanent fund, while Federal mineral royalties are used only for roads and schools. In 
Montana, the State share of Federal leasing and royalty revenues is divided equally between the 
highway and school fund, while State leasing and royalty revenues go to the State school trust. 
And in North Dakota, both State and Federal leasing and royalty revenues go to the State's 
school fund. 

(a) Labor supply. —A serious question raised by some analysts has been whether the supply of 
labor will, even with immigration, be sufficient to fill demand. It can be argued, for example, that 
coal-related employment will pay wages higher than the prevaiUng wages in other sectors. Labor 
could be bid away from these sectors by coal-related developments. This will be particularly 
critical to the agricultural and service sectors of the economy. Traditionally, these sectors have 
not been able to pay the level of wages that energy companies anticipate paying. It may be 
difficult for them to compete in the future labor market. Substantial substitution of capital for 
labor may be necessary in these sectors. It must be stressed that further empirical research is 
needed. Chronic labor shortages do, however, appear to be a reasonable possibility. 



V-10 



Table 5-4.— Type of taxes and levels of Government to which the revenues accrue** 









School 








State 


County 


equaliza- 


Long-range 






general 


general 


tion or 


building 


Other 




fund 


fund 


district 
fund 


fund 




Montana 












Strip coal mine tax 


X 


X 








State personal income 


X 




X 


X 




Electric energy 


X 










Corporation license tax 


X 




X 


X 




Property tax (includes net 


X 


X 


X 






proceeds) 












Resource indemnity tax ' 










X 


North Dakota 












State corporate income 


X 










State personal income 


X 










Business and corporation 


X 










privilege 












Sales 


X 










Property 


X 


X 


X 






Wyoming 












Severance 


X 










Sales-service-use 


X 










Conservation 


X 


X 








Property* 













*Revenues from this tax are divided between the local governments based on their mill levy, 
e.g Foundation Program Fund, county tax fund, special district fund, and school tax fund. 

TThe Montana Resource Indemnity Trust Tax is levied on all mineral resources. The annual 
income may be legislatively appropriated to deal with local problems related to mineral 
development. 

**Information for South Dakota and Nebraska was not included in the work group analyses. 



V-11 



(b) Population. -OvQT recent years, most of the rural areas of the Northern Great Plains have 
had a population dedine. Despite the population decline in rural areas, there was growth in the 
larger cities and in those communities that are closely tied to energy development. For instance, 
during the 10-year period between 1960-70 Gillette, Wyoming, experienced a population increase 
of over 100 percent; Lame Deer-Ashland, Montana, had a population increase exceeding 27 
percent while Stanton and Center in North Dakota had population increases of over 26 and 30 
percent, respectively. 

Although population growth is occurring in some areas^ population densities are still quite low 
in the principal impact area as a whole. In 1970, the area averaged about 7 persons* per square 
mile compared to the national average of 67. 

While many communities within the Northern Great Plains will be impacted by coal 
development and subsequent population increases, most of the immediate impact is likely to 
result in local communities where the plants will be located or where the employees reside. 
Communities like Gillette and Sheridan in Wyoming; Forsyth, Hardin, Colstrip and Lame Deer in 
Montana; and Beulah and Hazen in North Dakota all will be affected by coal development. Table 
5-5 presents the projected population that would occur in these selected communities as a result 
of alternative levels of coal development. Presently, both Sheridan and Gillette in the Wyoming 
impact area are regionally important service centers. If CDP III occurs, Sheridan could become 
not only a major residential center for coal development in adjacent areas of Wyoming, but 
Montana as well, while Gillette has the potential of becoming the dominant wholesale, 
transportation, and service center for the entire Powder River Basin area. 

(c) Institutional and Community Services.-The communities impacted by coal development 
are expected to experience a rapid growth in demand for urban services. None of the services in 
any of the counties that will be directly affected by construction of gasification plants are 
capable of handling an increased population without major adjustments. The type of adjustment, 
however, may not be as important as the rate of adjustment and many communities may find it 
difficult to adjust rapidly. It is likely that the smaller communities will be impacted the most. 



This is based on the census definition where communities are considered urban if their populations are over 2,500. 
This compares to a regional density of 4.4 persons per square mile as described in land resource section. 



V-12 



Table 5-5.— Population projections for selected communities 
CDPI, II, III-1980, 1985, 2000 



Town 


CDP 


1970 


1980* 


1985* 


2000* 






All in thousands 


North Dakota 










Beulah 


I 


1 


2 


2 


3 




II 




2 


5 


9 




III 




7 


13 


23 


Hazen 


I 


1 


2 


2 


3 




II 




2 


5 


9 




III 




8 


13 


23 


Montana 












Hardin 


I 


3 


3 


3 


3 




II 




3 


3 


8 




III 




3 


8 


23 


Forsyth 


I 


2 


3 


3 


3 




II 




3 


4 


4 




III 




4 


5 


6 


Colstrip 


I 


0.4 


3 


3 


3 




II 




3 


6 


6 




III 




6 


10 


13 


Lame Deer 


I 


1 


1 


1 


1 




II 




1 


1 


1 




III 




1 


6 


6 


Wyoming 












Gillette 


I 


7 


12 


12 


13 




II 




14 


19 


21 




III 




17 


37 


58 


Sheridan 


I 


11 


13 


15 


15 




II 




16 


23 


31 




III 




19 


32 


48 



*Estimates represent an incremental increase over the 1970 level of population. The increase 
represents only the population associated with coal development as specified in the CDP's. 
Population increases that may be added by other activities have not been estimated. 



V-13 



since their ability to absorb growth and finance needed services are more Umited than the larger 
communities. 

Services provided by nonprofit organizations, including critical medical care will be strained by 
rapid population increases. This kind of service cannot be easily stretched and some communities 
are finding these services difficult to provide. 

Publicly provided services such as education and municipal water services all require large 
capital outlays and long time periods to expand. The demand for education is instant upon arrival 
of workers' school-age children and presents one of the major problems the communities will face 
in coping with a rapid influx in population. 

A number of services are financed largely through property taxes, but many construction 
workers will own little property and will leave before the industrial plant they are building is on 
the tax roles. 

During the construction phase of development school enrollment will fluctuate greatly in the 
affected communities. More stable enrollment can be expected, however, during the operational 
phase. Schools built to serve construction-related families can be used to serve the families of 
operational personnel during the later development stages and at a time when revenues will be 
more readily available to help finance needed facilities. 

In order to visualize coal-related educational needs in the impacted communities, the number 
of students that may be added to existing enrollment and the associated facility cost is provided 
in table 5-6. These estimates reflect requirements associated with the operational phase of 
development only. 

In CDP I, impacts will be localized in communities near the plant and mine sites and in many 
areas existing capacity could be expanded to handle the anticipated growth. 

The population increases projected for CDP II and III, however, are great enough so that even 
the larger towns located near the development will be affected. If the later stages of development 
in these higher coal development profiles occur, a whole set of new institutions would be 
required since the schools, police and fire protection services, and civic organizations would be so 
large that they would have to adjust. In other words, scaling has an upper limit where a change in 
kind as well as size will occur. This could bring about serious fiscal problems in those 
communities that do not have the physical capacity to handle an increasing population. 



V-14 



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V-15 



For example, in CDP II, Gillette is expected to be the most affected community during the 
early stages of development but Sheridan will be more effected in the later years. Gillette's school 
enrollment would increase by 2,300 in 1980 and by another 2,300 by year 2000. Total capital 
cost of meeting these needs would be about $18 million. Sheridan's school enrollment would be 
about 1,600 in 1980 and increase to a total of 7,000 in year 2000. The total cost of providing 
these facilities would be about $26 million. 

If CDP III were to occur, Gillette would be the most affected community throughout the 
development period. Approximately 3,300 students would be added to Gillette's school 
enrollment by 1980, almost twice present enrollment. Total enrollment would increase to 16,700 
by year 2000. The estimated capital cost of providing facilities for these students would be $13 
million in 1980, and $66 million by year 2000. 

No data regarding governmental expenditures for the principal impact communities were 
available.'' Suffice it to say, however, as population increases, stress will be placed upon existing 
service facilities and expenditures for facility expansion will be required. This will be particularly 
true for the later stages of development visualized in CDP II and III. 

(d) /^ow5mg.— Regardless of what CDP level is assumed, coal-related growth will impact on the 
commercial service sectors of the Northern Great Plains communities. Of the many services that 
will be affected, housing will be the one of most critical importance. 

In many Northern Great Plains communities, housing is already in short supply, particularly in 
towns like Gillette, Colstrip, Beulah, and Hazen which have felt or are beginning to feel the 
impact from energy development. Mobile homes are meeting the needs of many of the people 
and relieving the housing shortage to some extent. This is most evident in Gillette, where in 1973, 
about 35 percent of the town's 2,000 housing units were in mobile homes, and the number is 
rapidly increasing. The city is currently planning for a development of 380 new trailer homes 
during 1974. 

In the future, mobile homes will continue to play a major role in meeting the housing demands 
of impacted communities. This will be most evident in the early years of development when as 
much as 70 percent of new housing may be composed of mobile homes. As development phases 
into maturity, however, the percentage of mobile homes can be expected to decrease and the 
number of permanent dwellings substantially increase. Even if 70 percent of new housing is 
mobile homes, a significant demand will be placed on the local construction industry to meet 



7 

Although no governmental expenditure data were available from the communities, FY 1974 budgets for the six county area 
where the communities are located were as follows: Big Horn ($1.5 million), Rosebud ($2.2 million), Mercer ($1.2 million), 
Oliver ($0.5 million), Campbell ($3.4 million), and Sheridan ($3.2 million). 

V-16 



new home construction needs, for example, in Gillette the number of housing units would 
increase from 2,000 in 1970 to 4,000 by 1980, and 22,000 by the ytar 2000-CDP III. This 
represents an annual increase of 900 homes per year over the 20-year period. If 70 percent of 
these units are comprised of mobile homes, approximately 1 ,200 permanent housing units would 
be required by 1980 and another 330 annually during the next 20 years. This would place a 
tremendous demand on the local home building industry in Gillette, which in 1973 had about 40 
new housing starts. 

(1) Operational phase .—Wow^ing needs of the various communities are summarized in table 
5-7. As the estimates indicate, housing requirements will vary considerably by community and 
CDP. Housing needs for CDP I were not evaluated in depth; however, by the year 2000, a total 
of 2,000 additional housing units would be required to meet the demand in Gillette, and 1 ,000 
additional units in Colstrip for CDP I. Other communities will be impacted but to a lesser 
degree. 

Table S-1 .—Increased housing needs for selected communities— operational phase development 

CDP II, III- 1980, 1985, 2000 



Town 


CDP 


1970 


1980 


1985 


2000 






All in thousands 


Buelah 


0.5 





2 


1 








3 


2 


5 


Hazen 




0.5 





2 


1 








3 


T 


5 


Hardin 




1 








2 











2 


7 


Forsyth 









1 











1 





1 


Colstrip 




0.4 


1 


1 











2 


9 


1 


Lame Deer 




0.5 




















2 





Gillette 




2 


3 


2 


1 








4 


9 


9 


Sheridan 




4 


2 


3 


4 








3 


6 


7 



V-17 



Of the communities identified in the housing study, Lame Deer, Hardin, and Forsyth would 
be the communities least affected by coal development in CDP II. A CDP III, however, could 
require substantial expansion in all communities, generally after 1985. In CDP II, Lame Deer 
will not require additional housing in any time frame, but under the assumptions of CDP III, 
2,000 units would be required by 1985, remaining at this level through the year 2000. Because 
of the anticipated development pattern, Hardin should not require coal-related housing until 
the year 2000— CDP II, but would require substantial expansion if CDP III were to occur— a 
total of 9,000 units in the 15-year period between 1985 and the year 2000. 

Forsyth, a community which has experienced the expansion and contraction of the oil 
industry in the past decade, would be required to provide 1,000 additional housing units by 
1985 with no further expansion anticipated through the year 2000-CDP II. In CDP III, 2,000 
units would be required, 1,000 by 1980 and another 1,000 units by the year 2000. 

Sheridan, Wyoming, would require the greatest number of housing units in CDP II with 
about 9,000 new units required between 1980 and 2000. Gillette, Wyoming, would require the 
greatest number if CDP III, requiring about 22,000 housing units during the same 20-year 
period. 

(2) Construction p/za^e. -Although the total housing needs associated with the construction 
phase of development have not been estimated, the increase in housing resulting from 
construction of a single gasification or powerplant has been determined (fig. 5-5). These 
estimates reflect a 5- and 3-year construction shcedule for a gasification and powerplant, 
respectively. 

As figure 5-5 suggests, the housing needs of construction workers will fluctuate considerably 
and will significantly impact the communities affected by development. In fact, the demands 
will be even greater than those anticipated for the operational phase of development. The peak 
construction year could require three to four times the number of permanent employees 
needed in the operational phase and thus create substantially greater housing demands; 
although of relatively short duration. 

(e) Revenues.—The ability of local governments to provide increased levels of service as well as 
new services may well become one of the most critical problems associated with coal 
development in the Northern Great Plains. Conceiveably housing and education may be the most 
visibly impacted service areas. 



V-18 



3,500 



3,000 



2,500 



£ 2,000 
111 

Z 

o 



O 1,500 

X 



1,000 



500 







• 








4' 


1 
\ 
\ 

\ 
\ 
\ 








i 


\ 

\ 

\ 
\ 
\ 






i 
1 
1 

/ 




X 


\ 




f 

1 

1 
1 
1 


* 




1 


# 


m 
1 
1 

1 
1 
1 








\ 


1 y 











CONSTRUCTION YEARS 



Figure 5-5. Housing requirements necessary to meet the needs of construction workers 
associated with a single gasification plant and powerplant. 



Securing sufficient capital to expand classrooms and construct new schools and homes will be 
a very difficult obstacle to overcome in most instances. Complicating the above situation is the 
potential of a very high short-term demand for these services during the construction phase of 
coal development. The short-term demands potentially could become very severe in CDP II and 
further aggrevated to a heightened degree under CDP III levels. 

Revenue— service demand lags, capital shortages, jurisdictional disputes, and a rapidly 
fluctuating population base have the potential for severely testing the structure of local 
government and non-governmental services. Additional study, and site specific development plans 
are needed before any firm cost estimates can be made and before any firm strategy to remedy 
these problems is undertaken. 

(1) Tax revenues— ¥\xr\ds to meet budget requirements will be one of the most critical 
problems the communities will face in their efforts to cope with rapid development. This will 
be most evident in the construction phase of development when coal-derived revenues will not 
be available for funding purposes. Assuming the state governments can effectively reapportion 
these revenues to local levels of government, prospects for financial relief seem good. Within a 
six county area^ where revenues were estimated (assuming current tax rates and methods of 
taxation), new revenues generated annually in CDP I would be $44,000,000 in 1980 and 
approximately $88,000,000 in the year 2000. In CDP II annual revenues would be 
$47,000,000 in 1980 and $172,000,000 by the year 2000. Tax revenues in CDP III would be 
substantially greater: $76,000,000 in 1980 and $373,000,000 by year 2000. 

The primary levels of government that will benefit from these new tax revenues include the 
county fund, local school district fund, and the state general fund. The state general fund and 
local school district fund are expected to benefit the most, claiming approximately 75 percent 
of all tax revenues. Other levels of government that will benefit, albeit to a lesser extent, 
include the county fund. School EquaHzation Fund, Long-Range Building Fund, foundation 
program fund, and the special district fund. 

(2) Coal royalty revenues— Coal royalties^ , although substantially smaller than tax 
revenues, will nevertheless be important. 

Within the six county area, where over 85 percent of all coal royalty revenues would be 
generated, annual revenues in CDP I would total approximately $14,000,000 in 1980 and 



-Six-county area includes Rosebud, Big Horn, Montana; Sheridan, Campbell, Wyoming; Oliver, Mercer, North Dakota. 
Coal royalty revenues will be divided almost evenly between the State and Federal Governments, with the Federal royalty 
adjusted to account for the 37.5 percent amount that isrequired by the Mineral Leasing Act to be returned to the States. These 
revenues were estimated on the basis of a State and Federal royalty rate of $0.2 5 per ton. 

V-19 



increase to sliglitly more than $20,000,000 in year 2000. In CDP II, revenues would range 
from $17,000,000 in 1980 to $42,000,000 in year 2000. And, in CDP ill, 1980 revenues 
would approach $22,000,000 annually, rising to $132,000,000 in the year 2000. 

As illustrated here, the prospects for financing coal-induced service delivery systems seems 
quite good. Total revenues generated by year 2000 in CDP III may exceed one-half billion 
dollars annually. Sufficient tax revenues, however, will not be available to meet fund 
requirements during the construction phase of development and in the first few operating 
years. This time lag between revenue generation and service needs may place a severe budget 
strain on communities impacted by coal development. This problem is occurring in some NGP 
communities today. 

5-4. Impact on Indians as a Result of Coal Development.— T\\q. Northern Great Plains five-state 
study area encompasses all or parts of 23 Indian reservations. These reservations contain 
Indian-owned land ranging from about 20,000 to millions of acres, and have Indian populations 
ranging from a few hundred to over 1 1,000. The reservations, in total, contain over 13 million 
acres of land, covering more than 20,000 square miles, an area considerably larger than many 
states. They provide a resource base for over 80,000 tribal members. 

There is a great amount of institutional complexity regarding the Native Americans in relation 
to the rest of society in the Northern Great Plains. Indian reservations are independent political 
entities, each having its own political structures and legal codes. The states in which they are 
located have little if any jurisdiction within the reservation boundaries. The reservations represent 
a great diversity of subethnic groups, and differ significantly in their approach to socio-economic 
situations. They have historically been socio-economic as well as geographic islands in a region 
already isolated by great distances. 

Services, normally the responsibility of local or state government in a non-Indian community, 
are performed in a cooperative effort between the various tribes, the BIA, and other Federal and 
State agencies. This includes a United States trust responsibility in the performance or assistance 
in the development, use, control, and protection of Indian lands and land-related resources as 
well as the construction, maintenance, and operation of irrigation systems and the development 
of recreational services and areas. Socio-economic services such as educational, health, and credit 
facilities are derived from BIA and the Public Health Service, as well as from standard 
Government and private sources. 



V-20 



On some reservations, over half of the Indian land is owned by the tribal entity. On others, the 
very large majority is in individual Indian allotments. The amount of Indian-owned lands 
decreased steadily during the first 65 years of this century. This occurred through cession to the 
Federal Government or by sale to non-Indian owners. During the past 3 decades, several tribes on 
the Missouri River have lost considerable amounts of land through eminent domain to large 
main-stem reservoirs. This erosion of land-ownership has been minimized in recent years, and 
most of the tribes are now taking specific steps to consolidate ownership, to acquire key tracts of 
land, and to further minimize land attrition by purchasing individual allotments that otherwise 
would be sold to non-Indians. 

The land on the Indian reservations ranges from high forested mountain areas in Montana to 
semiarid grassland typified by several South Dakota reservations, as well as fertile irrigated river 
bottom valleys. Like non-Indian lands, some areas are underlaid by the Fort Union Formation, 
which contains huge coal reserves. Special attention is being given to the development potential 
and jurisdictional aspects of the Indian water and other mineral resources in the Northern Great 
Plains Region. The specific identification and quantification of these resources and rights is a 
major effort of the Native American Natural Resources Federation of the Northern Great Plains. 
A report by this Federation entitled ''Declaration of Indian Rights to the Natural Resources in 
the Northern Great Plains States'' is appended to this report. 

(a) Tlie Six Most Affected Reservations.— Table 5-8 shows the land area and population of the 
six reservations in Montana and the Dakotas that will feel the major social and economic impact 
from coal development. These six reservations are home for about 25,000 Indians and encompass 
over 5.6 million acres— an area larger than New Jersey. About equal acreage of coal rights lie 
partly within and partly outside the reservations. Tliese coal reserves probably amount to billions 
of tons. 

(b) Population. -All six reservations have experienced a significant population increase in the 
last 10 years (table 5-9). The Indian population increase contrasts sharply with the overall 
population changes that occurred in the states where the six reservations are located. 



V-21 



Table 5-8. -Indian land and residents, by reservation, 1973 



Reservation 


State 


Indian-owned 
land (acres)* 


Indian resident 
population 


Crow 
Fort Peck 

Northern Cheyenne 
Fort Berthold 
Standing Rock 
Cheyenne River 


Montana 

Montana 

Montana 

North Dakota 

North Dakota, South Dakota 

South Dakota 


1,562,077 
961,857 
434,420 
420,718 
846,684 

1,405,178 


4,334 
6,202 
2,926 

2,775 
4,868 
4,335 


Total 




5,630,934 


25,440 



* Acres include land both on and off the reservation. Source: Bureau of Indian Affairs (1974). 

(c) Age.-lht reservation residents are quite young; nearly half of them are under 16 and 
nearly two-thirds are under 25 years of age. Separate analysis of the 1970 census shows that 
about 40 percent of the population in both Montana and South Dakota were under 19 years of 
age. The Indian population of the six reservations in this category range from 53 percent on the 
Crow Reservation to about 62 percent on the Fort Peck Reservation. 

The high percentage of the Indian population in the younger age groups, compared to the 
relatively low populations in the group 45 years and older, indicates a considerable potential for 
an increased Indian labor force. It also contributes to a high degree of dependency, with over half 
of the total population being either under 1 6 years of age or over 65 years of age. 



Table S-9 -Indian population change, 1963-73 






Popu 


ation 






1963 


1973 


Percent increase 


Crow 
Fort Peck 

Northern Cheyenne 
Cheyenne River 
Fort Berthold 
Standing Rock 


3,678 
3,390 
2,166 
3.421 
2,408 
4,300 


4,334 
6,202 
2,926 
4,335 

2,775 
4,868 


17.8 
82.9 
35.1 
26.7 
15.2 
13.2 


Total 


19,363 


25,440 


31.4 



Source: Bureau of Indian Affairs (1974). 



V-22 



(d) Labor Force and Employment. -A\\ six reservations have higher unemployment rates than 
the states where they are located. The 1970 unemployment rates reported by the Bureau of 
Labor Statistics for NGP reservations ranged from 11.6 percent to 29.1 percent. Comparable 
rates for Montana were 6.3 percent; for North Dakota, 4.6 percent; and for South Dakota, 3.3 
percent (table 5-10). 

Current Indian employment is primarily in agriculture, government, and tourism. The 
Northern Cheyenne also have a significant number of people employed in logging and milling. 
These skills provide the only nucleus for developing the Indian manpower for employment in the 
coal-related industries. If the Indian labor force is to be employed in coal industries, many of 
them will need to learn new skills. This assumes that members of the Indian labor force will 
actually seek employment in coal industries. The high unemployment rates on the reservations 
indicate that they would. 



Table 5-\Q. -Unemployment Rates: North Dakota, South Dakota, and Montana, compared to 
Indian reservations within their boundaries, 1970 



Area 


Percent unemployment 


Reservations 




Crow (Montana) 


11.6 


Fort Peck (Montana) 


25.7 


Northern Cheyenne (Montana) 


11.1 


Cheyenne River (South Dakota) 


18.4 


Standing Rock (North Dakota-South Dakota) 


29.1 


Fort Berthold (North Dakota)* 


— 


States 




Montana 


5.5 


North Dakota 


4.6 


South Dakota 


3.3 



*Data for Fort Berthold were not available. 

Source: Bureau of Labor Statistics, U.S. Department of Labor. 

However, many Indians are concerned about the adverse social and economic changes that coal 
development may bring and this may influence their decision regarding employment in the strip 
mines, and power and gasification plants. 



V-23 



(e) The Indian Family and Income -On the six reservations, Indian family size is larger, 
family income is lower, and a greater percentage of Indian families are in poverty than are found 
in the population standard of the six states where they are located, or in the U.S. population. 
These large families and low incomes are reflected in the percentage of the families having an 
income below the poverty level (table 5-1 1). 

Table 5-1 1 .-Family size and income: Indians compared to total population 









Famihes with 


Area 


Average 


Median 


incomes below 




family size 


family income 


poverty level 




Persons 


Dollars 


Percent 


Reservations:* 








Crow 


6.60 


5,260 


40.0 


Fort Peck 


6.54 


5,136 


46.7 


Northern Cheyenne 


5.37 


5,270 


39.8 


Cheyenne River 


5.99 


3,857 


54.8 


Fort Berthold 


6.10 


4,800 


45.3 


Standing Rock 


5.38 


3,667 


58.3 


States:t 








Montana 


3.55 


7,494 


10.4 


North Dakota 


3.72 


7,838 


12.4 


South Dakota 


3.66 


8,512 


14.8 


U.S. (all 








families') 


3.62 


9,433 


10.7 



*Data from Bureau of Indian Affairs (1974). 
tData from 1970 Census of Population. 



(0 Educational Levefe.— Educational levels on the six reservations are significantly lower than 
those for the total populations of the states in which these reservations are located. A brief 
comparison from U.S. census data for the Crow and. Standing Rock Reservations shows the 
median educational level of Indians over 25 years is almost 3 years less than non-Indian NGP 
residents. 



V-24 



(g) Anticipated Reservation Coal Development. -1\\q Standing Rock and the Cheyenne River 
Reservations have combined coal reserves estimates at some 100 million tons. However, 
commercial exploitation is considered marginal, and mining companies have thus far shown little 
serious interest in development. 

Fort Berthold Reservation is reported to have between 4 and 20 billion tons of measured and 
indicated lignite reserves, much of which is commercially recoverable under present technology. 
However, members of the three affihated tribes have expressed great concern about the cultural 
and environmental issues accompanying coal development and have imposed an indefinite 
moratorium on leasing and other mineral activity. 

The Fort Peck Reservation in eastern Montana has strippable lignite reserves estimated at 
several billion tons. However, coal developers have shown little interest in them, and no leasing or 
prospecting activities are currently underway. 

The Northern Cheyenne Reservation also has huge coal reserves, estimated in excess of 5 
billion tons of strippable deposits. However, tribal leaders and members are presently 
discouraging any development activity until the social and environmental effects of coal 
development are more fully understood. Testimony presented by the Northern Cheyenne 
Landowners Association at hearings regarding coal development conducted by U.S. Senator Lee 
Metcalf from Montana in April 1974 illustrates their concern: 

"The imminence of strip mining on the Northern Cheyenne Indian Reservation is bringing 

about a questionable future for the resources and Indian lands as well as the lives of the people 

exposed to it. The magnitude, nature, and rapidity with which this development will be 

brought upon the Cheyenne can only be felt as modem day genocide." 

The Crow Reservation is the only one of the six where coal development is in progress. It 
should be pointed out that although the Crow have initiated contractual agreements with mining 
interests to extract coal from ceded lands adjacent to their reservations, there is diversity of 
opinion among members of the tribe as to the desirabihty of coal development on the 
reservation. Public hearings held at the Crow Agency, Montana, in November 1973, produced 
testimony by tribal members both for and against coal development. 

Arrangements have already been made with Westmoreland Resources to mine at least 77 
million tons of Crow-owned coal on Sarpy Creek in the ceded area which Ues immediately north 



V-25 



of the present boundaries of the Crow Reservation. A final environmental impact statement 
relating to that mining operation has been prepared and filed. 

In addition, the Crows have either prospecting permits or leases with American Metals Climax 
Company, Gulf Minerals Resources Company, Peabody Coal Company, and Shell Oil Company. 
Explorations by these companies indicate a total of 4 to 4.5 billion tons of coal considered 
strippable under present economic and technical levels. 

Significant employment opportunities for Crow Indians may become available in coal-related 
industries on or adjacent to the Crow Reservation. If only two or three strip mines are operated, 
the work force would conceivably be mostly Indians, since they are assured preferential hiring 
and assuming they seek work in the mines. However, a significantly higher level of development 
may require very high non-Indian employment. This implies the possibility that the Indians might 
become a minority on their own reservation unless specific residential controls are exercised. To 
attempt to alleviate this problem, the Crows have been assured preferential hiring status in the 
coal industry. 

The potential impact of coal development on the culture and lifestyle of the different NGP 
Indian tribes has not been adequately explored. A complete knowledge of the culture and 
lifestyle of the Indian is a prerequisite of such an impact study. The only people having such 
knowledge are the tribal members; therefore it is logical to assume that they should be 
responsible for determining the potential beneficial or adverse impacts coal development may 
have on their culture and lifestyle. Many tribes have been struggling to develop the capability of 
making these studies and communicating the results to non-Indians. To date, this effort has been 
only marginally successful. In recent months, the Native American Natural Resources 
Development Federation of the Northern Great Plains has been organized by the NGP tribes to 
begin to address in a cooperative way the mutual problems the tribes are confronted with. A high 
priority need of this group is the description of their natural and cultural resource base and the 
protection of their water rights. If this group is successful, it may provide answers to many of the 
questions related to the issues raised in this section of the report. 

5-5. Agriculture and the Changes Expected From Coal Development. -Within the agriculture 
study area which includes portions of the four states of Wyoming, Montana, North Dakota, and 
South Dakota there are approximately 91 million acres of land, of which approximately 24 



V-26 



million acres are classified as cropland and 70 percent or 63 million acres is in pasture or 
rangeland. Of the cropland, 97 percent or 23 million acres is nonirrigated and 694,000 acres or 
the remaining 3 percent is under irrigation. Presented in table 5-12 is a summary of total land use 
in the study area. 

Within the study area there are 37,920 farms and ranches ranging in size from an average of 
815 acres in Ward County, North Dakota to 11,105 acres in Natrona County, Wyoming. The 
farms and ranches average approximately 2,400 acres in size with the average size of a farm in 
Montana— 3,771 acres; North Dakota— 1,294 acres; South Dakota— 3,598 acres; and 
Wyoming-6,329 acres. 

As of January 1, 1972, nearly 3.75 million head of cattle and calves stocked the farms and 
ranches, sheep and lambs numbered about 2 million, while hogs totalled slightly more than 
300,000. 

Wheat is the principal crop grown in the study area, and occupies about 30 percent of the total 
cropland under production. In 1971, slightly more than 130 million bushels of wheat averaging 
20 bushels per acre were produced on approximately 6.5 million acres. 

Other major crops produced in the study area include barley, flax, oats, corn, alfalfa, and sugar 
beets. Smaller acreage of potatoes, soybeans, sorghum, rye, and beans are also produced within 
the area together with poultry and dairy products. 

5-6. Agricultural Impact Assessment .-Coal development will affect Northern Great Plains 
agriculture in three principal resource areas— labor, water, and land. The method of mining, the 
level of development, and the method and location of coal utilization will determine to what 
extent agriculture will be affected. 

(a) Labor.-Stvip mining will compete directly with agriculture for labor resources as both 
industries place a premium on men in their physical prime who are accustomed to working with 
machinery and to working long hours outdoors. 

Operators of small farms who are underemployed in their farm businesses will provide a 
limited labor source for industry. It is expected that some of these operators may take advantage 
of the new off-farm job opportunities that industry provides and shift themselves and their 
families into higher levels of income while operating their farms on a part-time basis. Others may 
leave agriculture entirely, taking advantage of the higher income levels that coal-related industry 
will provide. Operators who are fully employed with adequate income from farming and ranching 



V-27 



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V-28 



and who do not hire much extra labor will be affected least by labor market changes. They likely 
will not be attracted to off-farm work and higher wages for hired labor will have Uttle effect on 
their operation. However, those operating large farms and ranches and hiring large amounts of 
labor will probably be forced to make significant adjustments in their operations particularly at 
the higher levels of coal production as envisioned under CDP II and III. These adjustments which 
may or may not be considered desirable may include dropping certain labor-intensive enterprises, 
adopting labor-saving techniques, and perhaps even reducing the size of their farming operation. 

An overview of the affect that coal development will have on the labor resources in the 
Northern Great Plains suggests that the supply of labor available to agriculture will be reduced. 
This will not cause major changes in farm organization in southwestern North Dakota, although 
the trend toward fewer and larger family farms based on labor-intensive enterprises, such as small 
grains and beef cattle, will likely be accelerated. Other parts of the Northern Great Plains will 
experience similar effects. Large ranching enterprises, like those located in some parts of 
Wyoming and Montana that are based largely on hired labor, may experience difficulty in hiring 
and retaining capable workers in competition with an expanding coal industry. 

(b) Water.-The amount of water necessary for coal development even at the CDP III rate of 
development may not necessarily compete with water used in existing agriculture production. 
However, conflict between agriculture and industry over future use of water that is beyond 
presently established uses and future coal development needs of the area may occur. It should be 
noted that industry is purchasing farms and ranches and converting the agricultural water right to 
industrial use. A discussion of this is presented in the Water section, part IV-2. 

It has been estimated that more than 3.0 million acre-feet of water is available, with new 
storage, in the Upper Missouri River Basin to meet future water requirements. Of the 3.0 million 
acre-feet that could be made available, 800,400 acre-feet is needed for CDP III. The balance, 
ostensibly, could be used to serve other uses including new irrigation development. Water use in 
the Yellowstone basin above the CDP II level of coal development would require additional 
storage facilities, however, to provide water above that needed for minimum flows. 

In 1970, there were about 694,000 acres of land under irrigation in the 63-county study area 
and little expansion has occurred since that date. With the current deemphasis on new Federal 
irrigation development, it is not expected that the irrigated base will, within the study area, 



V-29 



increase substantially in the near future. Presently, within the Yellowstone River Basin there are 
no projects which are being studied for new development that would meet Federally funded 
economic justification. There is some potential for new State-assisted and private irrigation 
development in the Yellowstone River Basin, but this is not expected to exceed 100,000 acres. 

North and South Dakota are each planning Federally funded projects that will expand their 
irrigation base, but these projects are outside the study area, and have been previously authorized 
under different formulation criteria. 

(c) Land.— More land will be removed from agriculture production as more coal is mined. 
Overall, however, it is not anticipated that industrial disturbances of the land will have a major 
effect on the area's agriculture productivity.' ° 

Under CDP II, for each of the years between 1985 and 2000, there would be approximately 
130,000 acres of land displaced.' ' This represents a 242 percent increase from the 38,000 acres 
assumed to be disturbed in CDP I and 138 percent less than the 309,000 acres would be 
disturbed if CDP III occurs. The amount of land displaced relative to the total land area of 91 
million acres is 0.04 percent in CDP I, 0.14 percent in CDP II, and 0.34 percent in CDP III. Table 
5-13 summarizes the amount of land that would be disturbed in all study area counties by profile 
and by time frame. 

The plant and mine sites are located almost entirely on rangeland. Therefore, it is not expected 
that irrigated agriculture will be affected and only a small percentage of the dry cropland in the 
study area would be disturbed. Table 5-14 summarizes the annual displacement of cropland in 
the study area in terms of production and acreage disturbed, beginning in 1980-CDP III. Only 
land assumed to be affected under CDP II and CDP III have been projected. Under CDP I, only a 
minor amount of cropland would be displaced. 

The loss in wheat production, which is the principal crop grown in the study area, would be 
approximately 2 percent of the total wheat being produced under CDP II and 4.5 percent (0.3 
percent national production) under CDP III. Barley and oat production would be affected but 
only to a relatively minor degree. 

The loss in vegetation to support cattle production in the Northern Great Plains area is 
minimal. For example, the level of surface mining indicates that a total of approximately 
224,000 acres of rangeland would be unavailable for grazing in year 2000. This includes natural 



Under the assumption that National Ambient Air Quality Standards have been adequately set to protect public health and 
welfare (including damage to^vegetation and animal life) and that these standards will be enforced, no impacts of air pollution on 
agriculture are anticipated. It should be noted however, that effects of some trace elements on vegetation are not fully understood 
and that standards have not been set for these elements. 

This represents the total amount of land out of production at any one time. 

V-30 



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V-31 



grazing lands currently being mined, and that which is in the process of rehabilitation following 
mining, as well as the acreage more-or-less permanently occupied by mine facilities, transmission 
lines, and other coal-related uses. At a rate of 3 acres per animal-unit-month (AIM), an 
equivalent of the grazing needs of only 6,200 animal units on a year-long basis would be lost. 

Statistical Reporting Service data on 1972 livestock numbers, converted to an 
animal-unit-basis, indicate a total of 3,178,410 animal-units of cattle, calves, sheep, and lambs in 
the region. Therefore, the total animal-units displaced by mining activities at the CDP III level of 
development in year 2000 would be only 0.0019 percent or less than 2/10 of 1 percent of 
present livestock numbers in the region. The value of the grazing lost, at a rate of $6 per AUM, 
would total $447,700 in year 2000 (table 5-15). 



Table 5-\4.— Cropland and associated production displaced annually 
between 1980 and 2000-CDP II and III 





CDP II 


CDP III 

Annual* 


CROP 


Acres 
displaced 


Production* 
bushels 


Acres 
displaced 


production 
bushels 


Valuet 
dollars 


Wheat 
Barley 
Oats 


13,807 
1,205 
3,866 


276,140 

44,505 

193,300 


28,400 
2,878 
7,328 


586,000 
106,500 
366,400 


714,000 

87,300 

172,200 




18,878 


513,945 


38,606 


1,058,900 


974,500 



*Based on 1971 average annual yield— wheat 20 bu./acre; barley 37 bu./acre; oats 50 bu./acre. 

'1971 weighted average seasonal price for Montana, Wyoming, and North Dakota as follows: 
wheat-$1.22/bu; oats $1.47/bu; and barley-$0.82/bu. (more recent values for these 
commodities would be considerably higher.) 



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Table 5-16 summarizes the number of animal units of grazing that will be affected in the 
five-county area as compared to the region as a whole. This is followed by table 5-17 which 
summarizes by time frame the amount of grazing land taken out of production and the value 
foregone as a result of coal development in the five-county primary impact area. 



Table 5-1 6.~Total animal units (A U) of grazing in five-county 
concentrated area and displacement-year 2000 



Area 



Animal units 
January 1972 



Animal units 
displaced 



Percent of 
present AU's 



All units in thousands 



Campbell County, Wyoming 
Big Horn County, Wyoming 
Rosebud County, Montana 
Mercer County, North Dakota 
Oliver County, North Dakota 


87,700 
98,500 
79,100 
76,700 


1,000 
700 
900 
600 


1.08 
0.67 
1.18 
0.78 


Total four sample counties 


342,000 


3,200 


0.92 


Region Total 


3,178,400 


6,200 


0.19 



Approximately one-half of the impact to the land in the Northern Great Plains will be 
experienced in the five-county area of Rosebud, Big Horn Counties, Montana; Campbell County, 
Wyoming; and Oliver and Mercer Counties, North Dakota, where most of the mining activities are 
expected to be located (table 5-17). In this five-county area by year 2000— CDP III, 3,200 animal 
units of grazing valued at $226,000 are estimated to be displaced by coal development. This 
represents about 0.92 percent of the total, 342,000 AUM's of grazing in the five-county area. 

As indicated here, the impact of coal production on agriculture in the aggregate will be 
relatively insignificant. The impact from mining, however, will be much more severe on an 
individual livestock operating unit basis. A single surface mine, with its attendant facilities, could 
displace a significant portion or all of an operating unit. A large mine operation, for instance, 
could affect several adjacent livestock units and the impact in such cases could be so extensive 
that the operating unit would cease to exist. 

The value of an individual tract or acreage to a livestock operating unit is frequently not based 
directly upon the productivity of that tract, but that the tract provides forage during a critical 



V-34 






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V-35 



period of the year when no other forage is available. It may, therefore, be an essential link in the 
year-round livestock operation, although it produces a small amount of the year-round forage 
supply (for example, the spring lambing range for a sheep unit or a subirrigated meadow which 
can be grazed when upland ranges are dry). 

An added "nuisance factor" would have to be taken into consideration also. This element 
would affect grazing values when a portion of a livestock operating unit is diverted to a 
nongrazing use such as surface mining. The location of the development in relation to other lands 
and to livestock handling facilities is important. If a mining development was located at the 
outside edge of a large grazing unit, it may have little effect other than reducing acreage available 
for grazing. If, on the other hand, the mining development was located near the center of a 
livestock ranch, it could seriously interfere with movement of livestock fencing and pasture 
arrangement, livestock water supplies and distribution, animal performance, and in general 
disrupt the overall farm operation. 

5-7. Societal and Cultural Impacts of Coal Z)eve/o/?/wertr.— Fundamental to the culture and 
way of life of persons who live in the NGP is the agricultural use of land. This culture is 
dominated by three distinct groups of people; farmers and ranchers, townspeople, and Indians. 
The first two groups share one culture while the Indians have a separate, yet related culture. 

To understand the impact of coal development on the culture and lifestyle of NGP residents 
we must understand the process by which a rural society becomes urbanized. The term 
"urbanization" can be described as a process which changes the way people relate to one another. 
As urbanization occurs, residents become less oriented toward other individuals in the 
community and more oriented toward institutions and extra-community forces. It includes a 
general dechne in local autonomy, exposure to different norms, and the destruction of the 
existing social order and the building of a new one. 

The non-Indian culture and way of life is centered around two features-the small size of the 
communities and the agrarian nature of the society. The persons who live in the area are 
accustomed to a generally slow pace of living, relatively little congestion, a well-integrated, stable 
society with an established sense of community where individuals are known and most 
face-to-face contact is with familiar persons, in short most of the attributes of a "primary" 



V-36 



community. Agriculture has long been the principal economic force in the area and the region's 
culture is firmly rooted in the American agricultural ideology.' ^ 

Initially, the impacts of urbanization will be greatest on the persons and communities closest 
to the actual development sites, with the impacts then diminishing in a descending scale with 
distance from the development sites. In the long run, however, all persons in the area wih be 
affected. The smaller the scale of development, the more likely it is that the impacts will be 
localized. 

Probably one of the major impacts will be the sheer size of the population growth within a 
very short time. Large numbers of persons with different values and orientations will move into 
the area because of the developmental activities. Most will likely move into rather small 
communities, doubling, tripling, or even quadrupling the present population. Congestion, 
crowding, the physical and mental stress associated with these phenomenon are all likely to be 
severe in many parts of the region, and most severe during the short-term construction period of 
development. All of these impacts are likely to reduce the perceived quality of life for many of 
the people already living there. 

With these changes, many residents, landowners as well as others, are challenged to modify 
their current life styles in order to accommodate changes in their environment. Some persons on 
fixed incomes (i.e., retirees) may be dislocated because of an increase in the cost of housing. 
Sportsmen may find favorite recreational areas disrupted by mining activities or "overcrowded" 
by newcomers. 

The changes in the culture and way of life of the area that may follow the development will 
vary not only with the level of development which occurs, but with the pace of that 
development. One likely set of impacts which will follow rapid development might be termed the 
"boom town" syndrome.' ^ Gilmore and Duff describe the syndrome as a "whole family of 
mental health symptoms and problems" that results from the rapid influx of a great many 
people. Families are crowded together in mobile homes in a strange environment; newly arriving 
families, particularly the blue collar families, seek acceptance into the community; social 
cohesion suffers as alienation and emotional distress feed on each other; and crime rates, suicide 
attempt rates, and alcoholism tend to increase. In short, the quality of life of persons, both 
newcomers and residents of the area, is degraded. 

See for example, E^dward Higbee, Farms and Farmers in an Urban Age (New York: Twentieth Century Fund, 1963) and 
Robert H. Salisbury, "Agriculture and Natural Resources," in J. W. Peltason and James M. Burns, Functions and Policies of 
Amedcan Government (Englewood Cliffs, N.J.: Prentice-Hall, 1967). 

John S. Gilmore and Mary K. Duff, "Statement to Public Lands Subcommittee, Interior Committee, U.S. Senate, Jan. 19 
1974" (Denver: mimeo, 1974) p. 10. ' ' ' 

V-37 



Of course, the boom might turn into a "bust" if exogenous factors force the closing of mining 
activities in the area. This, then, would lead to another series of impacts for the communities 
involved. 

The family as a social unit, is likely to be greatly affected by the changes introduced by the 
energy development activities. Traditionally, the rural family has been a strong social unit. In the 
rural setting, cohesiveness of the family is both the result of and mandatory for economic 
survival.' '* With the advent of urbanization and industrialization in the NGP, the family is likely 
to cease to be a basic unit of production. Individuals may seek employment outside of traditional 
family enterprises, such as the family farm, ranch, or store. Extended families within one 
household are less likely to exist as people migrate to other employment. 

These new values and interests often change existing values and culture. Such change generates 
stress on the residents, leading to a feeling of isolation, and sometimes alienation and conflict 
between established groups and newcomers. In other words, conflicts between some ranchers and 
miners could develop. Some communities might be "taken over" by newcomers, and long-term 
residents may withdraw physically or in terms of participation in community activities. 

As the newly emerging community stabilizes it may present new job opportunities and a higher 
economic standard of living than was possible in the old community. The variety of cultural and 
recreational opportunities would probably increase as would the availability of services. 

High emigration rates have existed throughout virtually the entire region for the past several 
decades, for almost all age groups.' ^ One expected impact of development is that the emigration 
rates would be significantly reduced, in large part because of the increased availability of 
desirable employment opportunities within the area. If this is to occur, then an additional 
measure of stability in terms of the residents could be anticipated. 

Most of the rural communities of the area have well defined and long established networks of 
social and political relationships. It is likely that one of the results of the anticipated changes in 
the area will be the fragmentation of these groups by the intrusion of relatively large numbers of 
persons into the area, and in effect, the creation of a new social order. Another likely impact will 
be the dilution of political power of the historically dominant groups (primarily landowners) 
within the impacted area. In the long run, new political alliances and groups will likely develop. 



14 

Sam Carnes. "Report to Work Group" (Evanston, 111.: mimeo, 1974), p. U. 
Professor Audie Blevins, personal communication, April, 1974. 



V-38 



A further major change in the way of life for some of the people in the area has been an 
increased social activity in planning and organizing for anticipated change. In effect, the 
anticipated environmental changes have resulted in activating groups and leaders into overt 
action. Many people who previously had not participated in community, civic, or political affairs 
have devoted large amounts of time and energy to organizing and participating in community 
affairs related to forthcoming development. 

Some of the impacts have already begun to occur. There has been some population growth and 
preliminary activities such as securing leases and mapping resources have begun to spur some 
changes in the area. One notable change among a sizable group of the population has been the 
creation of an aura of uncertainty and "unsettledness" about their future. Questions such as the 
following occur: "How much development will take place?" "When will the development take 
place?" "How fast?" "What will happen to the water table?" "Can the land be reclaimed 
effectively?" No longer can many people view the future in the same manner as they have for 
many years. Uncertainty about the future has materially reduced the quality of the present for 
many persons. 

In sum, the culture and way of life of persons in the impacted areas of the NGP will likely shift 
from the agrarian focused way of life which now exists to a larger, more urbanized way of life 
with all the advantages and disadvantages which that will entail. Some of the changes would 
likely come about without the energy development activities, but at a very much slower 
pace— over decades instead of in a few years. 



V-39